[Federal Register Volume 88, Number 231 (Monday, December 4, 2023)]
[Notices]
[Pages 84139-84140]
[FR Doc No: 2023-26538]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. ER24-482-000]

River Fork Solar, LLC; Supplemental Notice That Initial Market-
Based Rate Filing Includes Request for Blanket Section 204
Authorization

    This is a supplemental notice in the above-referenced proceeding of
River Fork Solar, LLC's application for market-based rate authority,
with an accompanying rate tariff, noting that such application includes
a request for blanket authorization, under 18 CFR part 34, of future
issuances of securities and assumptions of liability.
    Any person desiring to intervene or to protest should file with the
Federal Energy Regulatory Commission, 888 First Street NE, Washington,
DC 20426, in accordance with Rules 211 and 214 of the Commission's
Rules of Practice and Procedure (18 CFR 385.211 and

385.214). Anyone filing a motion to intervene or protest must serve a
copy of that document on the Applicant.
    Notice is hereby given that the deadline for filing protests with
regard to the applicant's request for blanket authorization, under 18
CFR part 34, of future issuances of securities and assumptions of
liability, is December 18, 2023.
    The Commission encourages electronic submission of protests and
interventions in lieu of paper, using the FERC Online links at http://www.ferc.gov. To facilitate electronic service, persons with internet
access who will eFile a document and/or be listed as a contact for an
intervenor must create and validate an eRegistration account using the
eRegistration link. Select the eFiling link to log on and submit the
intervention or protests.
    Persons unable to file electronically may mail similar pleadings to
the Federal Energy Regulatory Commission, 888 First Street NE,
Washington, DC 20426. Hand delivered submissions in docketed
proceedings should be delivered to Health and Human Services, 12225
Wilkins Avenue, Rockville, Maryland 20852.
    In addition to publishing the full text of this document in the
Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
internet through the Commission's Home Page (http://www.ferc.gov) using
the ``eLibrary'' link. Enter the docket number excluding the last three
digits in the docket number field to access the document. At this time,
the Commission has suspended access to the Commission's Public
Reference Room, due to the proclamation declaring a National Emergency
concerning the Novel Coronavirus Disease (COVID-19), issued by the
President on March 13, 2020. For assistance, contact the Federal Energy
Regulatory Commission at [email protected] or call toll-free,
(886) 208-3676 or TYY,<PHONE_NUMBER>.
    The Commission's Office of Public Participation (OPP) supports
meaningful public engagement and participation in Commission
proceedings. OPP can help members of the public, including landowners,
environmental justice communities, Tribal members and others, access
publicly available information and navigate Commission processes. For
public inquiries and assistance with making filings such as
interventions, comments, or requests for rehearing, the public is
encouraged to contact OPP at<PHONE_NUMBER> or [email protected].

    Dated: November 28, 2023.
Kimberly D. Bose,
Secretary.
[FR Doc. 2023-26538 Filed 12-1-23; 8:45 am]
BILLING CODE 6717-01-P


[Federal Register: April 12, 2007 (Volume 72, Number 70)]
[Notices]
[Page 18469-18470]
[DOCID:fr12ap07-49]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Project No. 12635-000]

Moriah Hydro Corporation; Notice Rejecting Late Intervention

April 6, 2007.
    On January 3, 2006, Moriah Hydro Corporation (Moriah) filed an
application for a three-year preliminary permit under Section 4(f) of
the Federal Power Act \1\ to study the proposed 189-megawatt Mineville
Pumped Storage Project No. 12635. Public notice of the application was
issued on April 20, 2006, with a deadline of June 19, 2006, for
comments and motions to intervene. On November 13, 2006, a preliminary
permit was issued to Moriah.\2\ The order became final on December 13,
2006.
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    \1\ 16 U.S.C. 797(f) (2000).
    \2\ Moriah Hydro Corporation, 117 FERC ] 62,149 (2006).
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    On March 7, 2007, the New York State Council of Trout Unlimited
(Trout Unlimited) filed a late motion to intervene in the permit
application proceeding. The permit application proceeding was
terminated upon issuance of the permit. Because there is no proceeding
in which to intervene,

Trout Unlimited's motion for late intervention is rejected.\3\
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    \3\ If the Moriah files a license application, public notice
will be issued; and Trout Unlimited will have an opportunity to
intervene and comment on the proposed project.

Philis J. Posey,
Acting Secretary.
 [FR Doc. E7-6916 Filed 4-11-07; 8:45 am]

BILLING CODE 6717-01-P


[Federal Register Volume 79, Number 237 (Wednesday, December 10, 2014)]
[Notices]
[Pages 73325-73326]
[FR Doc No: 2014-28828]

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DEPARTMENT OF HEALTH AND HUMAN SERVICES

Food and Drug Administration

[Docket No. FDA-2014-N-1998]

Patient-Focused Drug Development Public Meeting on Chagas Disease

AGENCY: Food and Drug Administration, HHS.

ACTION: Notice of public meeting; request for comments.

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SUMMARY: The Food and Drug Administration (FDA) is announcing a public
meeting and an opportunity for public comment on Patient-Focused Drug
Development for Chagas disease. Patient-Focused Drug Development is
part of FDA's performance commitments in the fifth authorization of the
Prescription Drug User Fee Act (PDUFA V). The meeting is intended to
allow FDA to obtain patients' perspectives on the impact that Chagas
disease has on their daily lives, as well as their perspectives on the
available therapies for Chagas disease. FDA is also interested in
discussing issues related to scientific challenges in developing drugs
to treat Chagas disease. In the afternoon, FDA will provide information
for and gain perspective from patients and patient advocacy
organizations, health care providers, academic experts, and industry on
various aspects of clinical development of drug products intended to
treat Chagas disease. The input from this public meeting will help in
developing topics for further discussion.

DATES: The meeting will be held on April 28, 2015, from 9 a.m. to 5
p.m. Registration to attend the meeting must be received by April 20,
2015. See the SUPPLEMENTARY INFORMATION section for information on how
to register for the meeting. Submit electronic or written comments by
June 29, 2015.

ADDRESSES: The meeting will be held at the FDA White Oak Campus, 10903
New Hampshire Ave., Bldg. 31 Conference Center, Sections B and C of the
Great Room (Rm. 1503), Silver Spring, MD 20993. Participants must enter
through Building 1 and undergo security screening. For more information
on parking and security procedures, please visit http://www.fda.gov/AboutFDA/WorkingatFDA/BuildingsandFacilities/WhiteOakCampusInformation/ucm241740.htm.
    Submit electronic comments to http://www.regulations.gov. Submit
written comments to the Division of Dockets Management (HFA-305), Food
and Drug Administration, 5630 Fishers Lane, Room 1061, Rockville, MD
20852. All comments should be identified with the docket number found
in brackets in the heading of this document.
    FDA will post the agenda approximately 5 days before the meeting at
http://www.fda.gov/Drugs/NewsEvents/ucm420130.htm.

FOR FURTHER INFORMATION CONTACT: Pujita Vaidya, Center for Drug
Evaluation and Research, Food and Drug Administration, 10903 New
Hampshire Ave., Bldg. 51, Rm. 1144, Silver Spring, MD 20993, 301-796-
0684, FAX:<PHONE_NUMBER><EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

I. Background on Patient-Focused Drug Development

    FDA has selected Chagas disease as the focus of a meeting under
Patient-Focused Drug Development, an initiative that involves obtaining
a better understanding of patients' perspectives on the severity of the
disease and the available therapies for the condition. Patient-Focused
Drug Development is being conducted to fulfill FDA's performance
commitments made as part of the authorization of PDUFA V under Title I
of the Food and Drug Safety and Innovation Act (Public Law 112-144).
The full set of performance commitments is available on the FDA Web
site at http://www.fda.gov/downloads/forindustry/userfees/prescriptiondruguserfee/ucm270412.pdf.
    FDA has committed to obtain the patient perspective in 20 disease
areas during the course of PDUFA V. For each disease area, the Agency
will conduct a public meeting to discuss the disease and its impact on
patients' daily lives, the types of treatment benefit that matter most
to patients, and patients' perspectives on the adequacy of the
available therapies. These meetings will include participation of FDA
review divisions, the relevant patient community, and other interested
stakeholders.
    On April 11, 2013, FDA published a notice (78 FR 21613) in the
Federal Register announcing the disease areas for meetings in fiscal
years (FYs) 2013 through 2015, the first 3 years of the 5-year PDUFA V
time frame. To develop the list of disease areas, the Agency used
several criteria that were outlined in the April 11 notice. The Agency
obtained public comment on these criteria and potential disease areas
through a notice for public comment published in the Federal Register
on September 24, 2012 (77 FR 58849), and through a public meeting held
on October 25, 2012. In selecting the disease areas, FDA carefully
considered the public comments received and the perspectives of its
review divisions. On October 8, 2014, FDA published a notice in the
Federal Register to initiate another public process to determine the
disease areas for FYs 2016 through 2017 (79 FR 60857). More
information, including the list of disease areas and a general schedule
of meetings, is posted at http://www.fda.gov/ForIndustry/UserFees/PrescriptionDrugUserFee/ucm326192.htm.

II. Public Meeting Information

A. Purpose and Scope of the Meeting

    As part of Patient-Focused Drug Development, FDA will obtain
patient and patient stakeholder input on symptoms of Chagas disease
(American trypanosomiasis) that matter most to patients and on current
approaches to treating Chagas disease. When left untreated, acute
Chagas disease may progress to chronic Chagas disease. There are
currently no FDA-approved drug therapies to treat acute or chronic
Chagas disease. FDA is committed to working with all stakeholders to
develop safe and effective therapies for affected individuals.
    The questions that will be asked of patients and patient
stakeholders at the meeting are listed in this section and organized by
topic. For each topic, a brief patient panel discussion will begin the
dialogue, followed by a facilitated discussion inviting comments from
other patients and patient stakeholders. In addition to input received
through this public meeting, FDA is interested in receiving patient
input addressing these

questions through written comments that can be submitted to the public
docket (see ADDRESSES). When submitting comments, if you are commenting
on behalf of a child, please indicate that and answer the following
questions as much as possible from the patient's perspective.
Topic 1: Disease Symptoms and Daily Impacts That Matter Most to
Patients
    1. What worries you most about your condition?
    2. Do you experience symptoms because of your condition? If so, of
all the symptoms that you experience, which one to three symptoms have
the most significant impact on your life? (Examples may include
irregular heartbeat, shortness of breath, difficulty swallowing,
stomach pain, or constipation.)
    3. Are there specific activities that are important to you but that
you cannot do at all or as fully as you would like because of your
condition? (Examples of activities may include sleeping through the
night, daily hygiene, driving, being a blood or organ donor, or for
women in reproductive age concern about getting pregnant and
transmitting the infection to your children, etc.)
    4. How have your condition and its symptoms changed over time?
    5. Do your symptoms come and go? If so, do you know of anything
that makes your symptoms better or worse?
Topic 2: Patient Perspectives on Current Approaches To Treat Chagas
Disease
    1. What are you currently doing to help treat your condition?
(Examples may include prescription medicines, over-the-counter
products, and other therapies including non-drug therapies such as diet
modification.)
    a. What specific symptoms do your treatments address?
    b. How has your treatment regimen changed over time, and why?
    2. What are the most significant downsides to your current
treatments, and how do they affect your daily life? (Examples of
downsides may include bothersome side effects, length of treatment,
number of pills to take daily, going to the hospital for frequent
checkups or treatment, restrictions on driving, potential consequences
to your health and your child's health during pregnancy, etc.)
    3. What specific things would you look for in an ideal treatment
for your condition?
    In the afternoon, discussion will be related to scientific topics,
with the goal of understanding issues that may affect the development
of drugs for the treatment of Chagas disease and identifying topics for
future discussion. Discussion topics for the afternoon will include
designs and endpoints for clinical trials as well as appropriate trial
populations.

B. Meeting Attendance and Participation

    If you wish to attend the meeting, visit http://chagasdiseasepatientfocused.eventbrite.com. Please register for the
meeting by April 20, 2015. If you are unable to attend the meeting in
person, you can register to view a live Webcast. You will be asked to
indicate in your registration whether you plan to attend in person or
via the Webcast.
    Seating will be limited, so early registration is recommended.
Registration is free and will be on a first-come, first-served basis.
However, FDA may limit the number of participants from each
organization based on space limitations. Registrants will receive
confirmation once they have been accepted. Onsite registration on the
day of the meetings will be based on space availability. If you need
special accommodations because of a disability, please contact Pujita
Vaidya (see FOR FURTHER INFORMATION CONTACT) at least 7 days before the
meeting.
    Patients who are interested in presenting comments as part of the
initial panel discussions must indicate in their registration which
topic(s) they wish to address. These patients also must send a brief
summary of responses to the topic questions by April 10, 2015, to
<EMAIL_ADDRESS>Panelists will be notified of their
selection approximately 7 days before the public meeting. We will try
to accommodate all patients and patient stakeholders who wish to speak,
either through the panel discussion or audience participation; however,
the duration of comments may be limited by time constraints.
    FDA will hold an open public comment period to give the public an
opportunity to comment. Registration for open public comment will occur
at the registration desk on the day of the meeting on a first-come,
first-served basis.

III. Comments

    Regardless of attendance at the Patient-Focused Drug Development
meeting, you can submit electronic or written comments, including
responses to the questions pertaining to Topics 1 and 2, to the public
docket (see ADDRESSES) by June 29, 2015. Received comments may be seen
in the Division of Dockets Management between 9 a.m. and 4 p.m., Monday
through Friday, and will be posted to the docket at http://www.regulations.gov.

III. Transcripts

    As soon as a transcript is available, FDA will post it at http://www.fda.gov/Drugs/NewsEvents/ucm420130.htm.

    Dated: December 3, 2014.
Leslie Kux,
Associate Commissioner for Policy.
[FR Doc. 2014-28828 Filed 12-9-14; 8:45 am]
BILLING CODE 4164-01-P


OMB No. XXXX XXXX Expires XX/ XX/ XXXX EPA FORM 5300 26 U. S. ENVIRONMENTAL PROTECTION AGENCY Quality Assurance Reporting Form for Use by Recipients of Assistance Agreements EPA Award Number:

Recipient Organization:

Name: Address: Project/ Program Period( starting and ending dates, mm/ dd/ yyyy):

Activity Group:

( check all that apply)   Infrastructure Development   Data Exchange, Analysis and Integration   Planning, Mentoring, and Training   Challenge Goal Task Output Outcome Quality Assurance Measures Instructions:  Please submit electronically to exchangenetwork@ epa. gov within 90 days of award.

 For Quality Assurance Measures, please refer to Solicitation Notice Appendix D: Quality Assurance Guidelines.

 For Goals, please refer to goals outlined in your assistance agreement work plan.


MEMORANDUM TO: Robert Wayland, Group Leader, Combustion Group, OAQPS, EPA FROM: Jim Eddinger, Combustion Group, OAQPS, EPA DATE: March 15, 2005 SUBJECT: Statistical Analysis of Mercury Test Data to Determine BDT for Mercury Emissions BACKGROUND Under section 111 of the Clean Air Act, new source performance standards ( NSPS) are to established based on best demonstrated technology ( BDT) considering cost, non air quality environmental impacts, and energy requirements. This memorandum presents an approach to determining an appropriate achievable mercury ( Hg) emission level for utility boilers fired with bituminous coal, subbituminous coal, lignite coal, and coal refuse that reflects BDT by using ICR 3 data.

For each coal type, ICR 3 data were reviewed to identify the units that were using technologies which were most effective at capturing ` from coal fired power plants. The technologies that appeared most effective in reducing Hg emissions were those that were installed, or likely would be installed, to comply with the current NSPS standards for particulate matter ( PM) and sulfur dioxide ( SO2). This combination of controls was most effective in reducing Hg emissions and, thus, is considered BDT.

For bituminous coal fired boilers, BDT is considered to be the combination of a fabric filter ( FF) and a flue gas desulfurization ( FGD) system. However, recent test data reports show that a bituminous coal based system including an SCR, ESP, and wet FGD may also be capable of meeting the performance limit set for bituminous coal fired Utility Units, and this was considered in setting the limit. The FGD may be either a wet scrubber system or a spray dryer absorber ( SDA). Of the 27 bituminous units listed in ICR 3, five units had a combination of a FF and a FGD. These units are listed in Table 1, along with the control efficiency, test results, and the BDT statistical analysis results.

For subbituminous coal fired units, BDT was determined to be depended on water availability. For subbituminous units that are under potential water restriction in the western United States and, thus, do not have a wet FGD system as an option for SO2 control, BDT is considered to be a combination of a FF with a SDA ( a dry FGD system). For subbituminous units that are not under water restrictions, BDT is a FF in combination with a wet FGD system. Of the 27 subbituminous units listed in ICR 3, two units have controls representing BDT for the wet 2 FGD subbituminous subcategory and four units have controls representing BDT for the dry FGD subbituminous subcategory. These units are listed in Table 2, along with the control efficiency, test results, and the BDT statistical analysis results.

For lignite coal fired units, BDT is considered to be either a FF/ SDA system or an ESP with a wet FGD system. Of the 12 lignite coal units listed in ICR 3, six units have controls representing BDT. These units are listed in Table 3 along with the control efficiency, test result, and the BDT statistical analysis results.

For coal refuse, the ICR 3 contain data on only two units. Both were fluidized bed combustion ( FBC) units equipped with fabric filters. Both have reported Hg control efficiency of greater than 99 percent. Therefore, BDT for coal refuse units would appear to be FBC/ FF combination. One unit fired waste anthracite, the other fired waste bituminous.

STATISTICAL ANALYSIS To determine the appropriate achievable Hg emission level for each coal type that reflects BDT, a statistical analysis was conducted to determine the appropriate control efficiency achieved by BDT. That is, the Hg reduction efficiency achievable for a source using BDT at the 90th percentile confidence limit using the one sided z statistics test ( i. e., the control efficiency which BDT is estimated to be able to achieve 90 percent of the time) was determined..

The statistical approach used was the one sided z statistics test using the equation:

confidence limit = average  z * standard deviation,

where the value of z is a function of the degrees of freedom and obtained from the statistical table listing t distribution critical values. The number of degrees of freedom for sample size n is simply n 1 for a one sample mean problem. The z values used in determining the 90 percentile confidence limit are:

Degrees of Freedom z value 2 1.886 3 1.638 4 1.533 5 1.476 The calculated control efficiency for BDT was then applied to the maximum annual average uncontrolled Hg emission rate for that coal type to determine the appropriate NSPS Hg emission 3 limits. The maximum annual average uncontrolled Hg emission rate were calculated from the annual average Hg fuel content values listed in ICR 3. This was considered reasonable since compliance with the NSPS will be based on a 12 month rolling average. Also the maximum annual average Hg fuel content was used for any unit in the subcategories because the NSPS is applicable nationwide. Using the highest Hg fuel content ensures that the developed NSPS limit are achievable by a unit located anywhere in the United States.

Bituminous Coal For bituminous coal fired units, the data used consisted of Hg control efficiency for the 5 units and the annual average fuel Hg content for all bituminous units. The control efficiency of the 5 units using BDT range from 83.8 percent ( Intermountain) to 98.5 percent ( Mecklenburg Cogeneration Facility). The annual average fuel Hg content for any bituminous coal unit range from a low of 0.0289 ppm ( Bay Front Plant Generating) to 0.3186 ppm ( AES Cayuga). However, the highest annual average fuel Hg content reported is 85 percent higher than the 2nd highest value and is considered an outliner compared to the other 36 bituminous units. Therefore, the 2nd highest annual average fuel Hg content of 0.1727 ppm ( Logan Generating Plant) was used to determine the maximum annual average uncontrolled Hg emission rate.

The average ( mean) of the control efficiencies is 94.8 percent, and the standard deviation is 6.2. Therefore, using the above equation:

confidence limit = average  z * standard deviation 90 percent confidence limit = 94.8  1.533 * 6.2 the achievable control efficiency for Hg emissions reflecting BDT for bituminous coal fired units is 85 percent.

Since the Hg emissions from any control system is a linear function of the inlet Hg fuel, assuming a constant control efficiency, the achievable Hg emission limit reflecting BDT for bituminous coal units was calculated by applying the 85 percent reduction to the the maximum annual average uncontrolled Hg emission rate. Therefore, the achievable Hg emission limit reflecting BDT for bituminous coal units is 1.96 lbHg/ trillion Btu. The analysis results are reported in Table 1.

Subbituminous Coal For subbituminous coal fired units, the same approach was performed as for bituminous coal units, except that the analysis was performed for the two subcategories of subbituminous units ( wet FGD and dry FGD).

Wet FGD units 4 The control efficiency of the 2 units using BDT range are 82.6 percent ( Clay Boswell 2) and 62.6 percent ( Comanche). Both of these unit are controlled only with a FF, but are considered to reflect BDT since the addition of a wet FGD would only enhance the Hg removal achieved by the FF. There are no subbituminous coal units listed in ICR 3 that have a combination of a FF and a wet FGD. The annual average fuel Hg content for any subbituminous coal unit range from a low of 0.0254 ppm ( Craig) to 0.1558 ppm ( Jack Watson). However, the highest annual average fuel Hg content reported is 46 percent higher than the 2nd highest value and is considered an outliner compared to the other 34 subbituminous units. Therefore, the 2nd highest annual average fuel Hg content of 0.0918 ppm ( San Juan) was used to determine the maximum annual average uncontrolled Hg emission rate.

The average ( mean) of the control efficiencies is 72.4 percent, and the standard deviation is 12.9. Therefore, using the above equation:

confidence limit = average  z * standard deviation 90 percent confidence limit = 72.4  1.476 * 12.9 the achievable control efficiency for Hg emissions reflecting BDT for wet FGD subbituminous coal units is 53 percent. Therefore, the achievable Hg emission limit reflecting BDT for wet FGD subbituminous coal units calculated by applying the 53 percent reduction to the the maximum annual average uncontrolled Hg emission rate is 4.0 lbHg/ TBtu. The analysis results are reported in Table 2.

Dry FGD units The control efficiency of the 4 units using BDT range from 23.8 percent ( Sherburne County Generation Plant) to 52.5 percent ( AES Hawaii). The annual average fuel Hg content for any subbituminous coal unit range from a low of 0.0254 ppm ( Craig) to 0.1558 ppm ( Jack Watson). However, the highest annual average fuel Hg content reported is 46 percent higher than the 2nd highest value and is considered an outliner compared to the other 34 subbituminous units. Therefore, the 2nd highest annual average fuel Hg content of 0.0918 ppm ( San Juan) was used to determine the maximum annual average uncontrolled Hg emission rate.

The average ( mean) of the control efficiencies is 35.4 percent, and the standard deviation is 12.15. Therefore, using the above equation:

confidence limit = average  z * standard deviation 90 percent confidence limit = 35.4  1.638 * 12.15 the achievable control efficiency for Hg emissions reflecting BDT for dry FGD subbituminous coal units is 16 percent. Therefore, the achievable Hg emission limit reflecting BDT for dry FGD subbituminous coal units calculated by applying the 16 percent reduction to the the maximum annual average uncontrolled Hg emission rate is 7.4 lbHg/ TBtu. The analysis results are reported 5 in Table 3.

Lignite Coal For lignite coal units, the control efficiency of the 6 units using BDT range from 33.3 percent ( Antelope Valley Station) to 57 percent ( TNP One). Two ( Heskett Station and TNPOne of the 6 units are fluidized bed combustion ( FBC) units which serves as a dry SO2 control. The annual average fuel Hg content for any lignite coal unit range from a low of 0.0620 ppm ( TNP One which was doubled from the reported value in ICR 3 based on later submitted information) to 0.1754 ppm ( Monticello). The highest annual average fuel Hg content of 0.1754 ppm was used to determine the maximum annual average uncontrolled Hg emission rate.

The average ( mean) of the control efficiencies is 44.6 percent, and the standard deviation is 8.8. Therefore, using the above equation:

confidence limit = average  z * standard deviation 90 percent confidence limit = 44.6  1.476 * 8.8 the achievable control efficiency for Hg emissions reflecting BDT for lignite coal units is 32 percent. Therefore, the achievable Hg emission limit reflecting BDT for lignite coal units calculated by applying the 32 percent reduction to the maximum annual average uncontrolled Hg emission rate is 13.7 lbHg/ TBtu. The analysis results are reported in Table 4.

For coal refuse units, the approach was similar except that no statistical analysis of the control efficiency was performed since the reported control efficiency for both units both was 99.9 percent. Both units are FBC boilers with FF. One unit combust waste anthracite, the other combust waste bituminous. The highest annual average Hg fuel content is 0.7029 ppm for waste bituminous. The achievable Hg emission limit reflecting BDT calculated by applying the BDT control efficiency of 99.9 percent to the maximum annual average uncontrolled Hg emission rate is 0.13 lbHg/ TBtu.

Conversation to Output Based Units The output based equivalent Hg emission limits of the BDT emission limits ( lb Hg/ TBtu heat input) calculated above can be computed by using the following equation:

Eo( lb/ MWh) = Ei( lb/ million) x n( heat rate) x 1000 kwh/ Mwh. For bituminous coal fired units the output based BDT limit would be: Eo( lb/ MWh) = 1.96 lb/ trillion x 10,667 Btu/ kwh x 1000 kwh/ Mwh. x 0.000001 where 0.000001 is the conversion factor from TBtu to million Btu OR Eo( lb/ MWh) = 1.96 lb/ trillion x 1.056 where 1.056 is the conversion factor from lb/ TBtu to lb x 10 5 lb/ Mwh 6 Therefore, for bituminous coal Eo( lb/ MWh) = 0.000021lb/ Mwh or 2.1 x 10 5 lb/ Mwh The output based Hg limits for each coal type would be:

bituminous coal = 2.1 x 10 5 lb/ Mwh subbituminous coal ( wet FGD units) = 4.2 x 10 5 lb/ Mwh subbituminous coal ( dry FGD units) = 7.8 x 10 5 lb/ Mwh lignite coal = 14.5 x 10 5 lb/ Mwh coal refuse = 0.14 x 10 5 lb/ Mwh Permit Information Recent, available permit Hg levels were evaluated for comparison with the limits presented above. The available permit information is presented in Appendix A. Comparison of the available permit limits with those developed above is a valid " reality check" on the appropriateness of NSPS's limits determined above that reflect BDT. Available permits on bituminous fired units have Hg emission limits ranging from approximately 2.0 x 10 5 lb/ MWh to 3.9 x 10 5 lb/ MWh; those for subbituminous fired units range from 1.1 x 10 5 lb/ MWh to 12.6 x 10 5 lb/ MWh. Considering the limited number of permits and the limited experience in developing appropriate Hg limits for those permits, the NSPS Hg emission limits developed above are in reasonable agreement with these permits. Insufficient permit information is available to do a similar comparison for lignite and coal refuse fired units but we have used the same analytic procedure for these subcategories. 7 TABLE 1 MERCURY DATA FOR BITUMINOUS COAL FIRED UTILITY BOILERS USED FOR DETERMINING BDT BDT: Fabric filter and spray dryer absorber OR Fabric filter and wet FGD Units using BDT:

Plant Name Unit Name Controls Test Average ( lb/ TBtu) Control Efficiency (%) Fuel Hg content during test ( ppm) Annual Average fuel Hg content ( ppm) Mecklenburg Cogeneration Facility GEN 1 FF/ SDA 0.1062 98.5 0.0967 0.0932 SEI  Birchwood Power Facility 1 FF/ SDA/ SCR 0.2379 97.2 0.1100 0.1470 Logan Generating Plant GEN 1 FF/ SDA/ SCR 0.3348 97.8 0.1800 0.1727 Clover Power Station 2 FF/ WS 0.3529 96.7 0.1594 0.0978 Intermountain 2SGA FF/ WS 0.2466 83.8 0.0233 0.0391 Average percent reduction of BDT units: 94.8 percent Standard deviation: 6.2 Percent reduction of BDT: 85 percent Highest annual average Hg content used: 0.1727 ppm ( Logan Generating Plant) Maximum annual average uncontrolled Hg emission rate: 13.3 lb/ T Btu Basis for calculated uncontrolled emission rate: Annual average fuel Hg content = 0.1727 ppm Average heat content of bituminous coal = 13,000 Btu/ lb ( Steam) 8 TABLE 2 MERCURY DATA FOR SUBBITUMINOUS COAL  WET FGD UNITS USED FOR DETERMINING BDT BDT: Fabric filter and wet FGD Units using BDT:

Plant Name Unit Name Controls Test Average ( lb/ TBtu) Control Efficiency (%) Fuel Hg content during test ( ppm) Annual Average fuel Hg content ( ppm) Clay Boswell 2 FF 0.6633 86.0 0.0567 0.0701 Comanche 2 FF 2.5931 65.8 0.0922 0.0767 Average percent reduction of BDT units: 72.4 percent Standard deviation: 12.9 Percent reduction of BDT: 53 percent Highest annual average Hg content used: 0.0918 ppm ( San Juan) Maximum annual average uncontrolled Hg emission rate: 8.7 lb/ T Btu Basis for calculated uncontrolled emission rate: Annual average fuel Hg content = 0.0918 ppm Average heat content of bituminous coal = 12,280 Btu/ lb ( Steam)

TABLE 3 MERCURY DATA FOR SUBBITUMINOUS COAL  DRY FGD UNITS USED FOR DETERMINING BDT BDT: Fabric filter and SDA Units using BDT: Plant Name Unit Name Controls Test Average ( lb/ TBtu) Control Efficiency (%) Fuel Hg content during test ( ppm) Annual Average fuel Hg content ( ppm) AES Hawaii A FBC/ FF 0.4606 52.5 0.0267 0.0279 Craig 3 FF/ SDA 0.7248 33.6 0.0100 0.0254 Sherburne County 3 FF/ SDA 7.5401 23.8* 0.0800 0.0528 Rawhide 101 FF/ SDA 7.7630 31.8 0.0733 0.0469 * Run 1 control efficiency, runs 2 and 3 were unrealistic and not used.

Average percent reduction of BDT units: 35.4 percent Standard deviation: 12.15 Percent reduction of BDT: 16 percent Highest annual average Hg content used: 0.0918 ppm ( San Juan) Maximum annual average uncontrolled Hg emission rate: 8.7 lb/ T Btu Basis for calculated uncontrolled emission rate: Annual average fuel Hg content = 0.0918 ppm Average heat content of bituminous coal = 12,280 Btu/ lb ( Steam) 9 10 TABLE 4 MERCURY DATA FOR LIGNITE COAL USED FOR DETERMINING BDT BDT: Fabric filter and SDA Units using BDT: Plant Name Unit Name Controls Test Average ( lb/ TBtu) Control Efficiency (%) Fuel Hg content during test ( ppm) Annual Average fuel Hg content ( ppm) R. M. Heskett Station B2 ESP CS 3.9768 56.1 0.0863 0.0881 Coyote 1 FF/ SDA 7.9523 38.2 0.1107 0.1348 Limestone 1 ESP/ WS 13.6612 51.0 0.1390 0.1460 Monticello 3 ESP/ WS 18.3232 47.6 0.4150 0.1754 Antelope Valley Station B1 FF/ SDA 4.0042 65.7 0.0620 0.0658 TNP One U2 FF 10.8596 59.2 0.2547 0.0620*

* ICR 3 value doubled based on later data received Average percent reduction of BDT units: 44.6 percent Standard deviation: 8.8 Percent reduction of BDT: 32 percent Highest annual average Hg content used: 0.1754 ppm ( Monticello) Maximum annual average uncontrolled Hg emission rate: 20.1 lb/ T Btu Basis for calculated uncontrolled emission rate: Annual average fuel Hg content = 0.1754 ppm Average heat content of bituminous coal = 8,735 Btu/ lb ( Steam)

TABLE 4 MERCURY DATA FOR COAL REFUSE FIRED UTILITY BOILERS USED FOR DETERMINING BDT Plant Name Unit Name Fuel Controls Test Average ( lb/ TBtu) Control Efficiency (%) Fuel Hg content during test ( ppm) Annual Average fuel Hg content ( ppm)

Kline Township Cogen Facility GEN 1 Waste Anthracite FBC/ FF 0.0816 99.9 0.3333 0.1733 Scrubgrass Generating Company GEN 1 Waste Bituminous FBC/ FF 0.0936 99.9 0.5267 0.7029 . 11 12 APPENDIX A 13 Table 1. Summary of Approved State Air Permits with Mercury Emission Limitations for Coal Fired Electric Utility Steam Generating Units Category State Permitting Authority Electric Utility Source Permit Information Project Status Comments Name Boiler Type Unit Capacity Type Approval Date Hg Emissions Limitation Bituminous Illinois EPA Prairie State Generating Co.

Prairie State Generating Station Units 1 and 2 PC 750 MW ( each unit) Construction 1 14 2005 Federal NESHAP limit Illinois EPA Corn Belt Energy Corporation Prairie Energy Power Plant PC 91 MW Construction 12 17 2002 4 x 10 6 lb/ MMBtu heat input Illinois EPA Indeck Elwood LLC ( Indeck) CFB 660 MW Construction 10 10 2003 2 x 10 6 lb/ MMBtu heat input South Carolina DHEC Santee Cooper Power Cross Generating Station Units 3 and 4 PC 660 MW ( each unit) Construction 2 5 2004 3.6 x 10 6 lb/ MMBtu heat input Under construction Facility subject to consent decree with EPA Kentucky DEP Thoroughbred Generating Station Units 1 and 2 PC 750 MW ( each unit) Construction 10 11 2002 3.21 x 10 6 lb/ MMBtu heat input Kentucky DEP Hugh L. Spurlock Power Station CFB 270 MW Air Quality Permit 8 4 2002 2.65 x 10 6 lb/ MMBtu heat input West Virginia DEP Longview Power PC 600 MW Construction 3 2 2004 1.46 x 10 2 lb/ hr based on a 3 hour average and 6.38 x 10 2 TPY based on 12 month rolling average.

Subbituminous Iowa DNR MidAmerican Energy Co.

Council Bluffs Energy Center Unit 4 PC 790 MW Construction 6 17 2003 1.7 x 10 6 lb/ MMBtu heat input PRB coal Supercritical boiler Sorbent injection Utah DEQ Sevier Power Company's NEVCO Energy CFB 270 MW Air Quality Permit 10 12 2004 4 x 10 7 lb/ MMBtu heat input Burns a mixture of western bituminous / western ( non SRB) subbituminous coal Arkansas ADEQ Plum Point Energy Associates PC 550 800 MW Operating 8 20 2003 12.8 x 10 6 lb/ MMBtu heat input Montana DEQ Bull Mountain Energy Roundup Power Plant Units 1 and 2 PC 390 MW ( each unit) MACT 7 25 2003 3.23 x 10 6 lb/ MMBtu heat input Montana DEQ Rocky Mountain Power Hardin Generation Project PC 113 MW Air Quality Permit 12 22 2004 5.8 lb/ TBtu heat input based on 1 hour average Permit decision under appeal Existing unit permit revision triggered by reconstruction Table 1 ( Continued)

Category State Permitting Authority Electric Utility Source Permit Information Project Status Comments Name Boiler Type Unit Capacity Type Approval Date Hg Emissions Limitation 14 Missouri DNR City Utilities of Springfield Southwest Power Station Unit 2 PC 275 MW Construction 12 15 2004 7.5 x 10 6 lb/ MMBtu heat input Arizona DEQ Tucson Electric Power Company Springerville Units 3 and 4 PC 400 MW ( each unit) Air Quality Permit 2 14 2002 6.9 x 10 6 lb/ MMBtu heat input Wisconsin DER WE Energies Elm Road Generating Station PC 615 MW ( each unit) Construction 1 14 2004 1.12 lb/ TBtu heat input in any 12 consecutive months PRB coal Supercritical boiler Wisconsin Public Service Corp.

Weston Plant PC 500 MW Construction 10 19 2004 1.7 lb/ TBtu heat input in any 12 consecutive months Permit decision under appeal PRB coal Supercritical boiler Sorbent injection Lignite Texas TCEQ Texas New Mexico Power Company TNP One Units 1 and 2 CFB 175 MW ( each unit) Air Quality Permit 5 12 1987 Maximum Allowable Emission Rates 0.3 lb/ hr, 1.3 TPY Permit to construct and operate Issued 5/ 12/ 87 Texas TCEQ Alcoa's Rockdale Power Plant CFB 1and CFB 2 CFB 216.5 MW Net ( each unit) Air Quality Permit 10 25 2003 Maximum Allowable Emission Rates 0.033 lb/ hr, 0.048 TPY While these units will be industrial boilers at a primary aluminum plant they are fed by a minemouth facility and by permit must meet 40 CFR Part 60 Subparts A and Da.

IGCC No units of this design have been permitted Coal refuse Kentucky DEP Kentucky Mountain Power CFB 250 MW Construction 6 15 2000 81 x 10 6 lb/ MMBtu heat input Coal refuse/ coal Illinois EPA EnviroPower of Illinois, LLC CFB 250 MW ( each unit) Construction 7 3 2001 4 x 10 6 lb/ MMBtu heat input Burns a mixture of bituminous coal refuse ( culm) and bituminous coal 15 Table 2. Summary of Air Pollution Control Configfurations for Coal Fired Electric Utility Steam Generating Units With Approved State Air Permits with Mercury Emission Limitations Category Electric Utility Source Air Emission Control Configuration Comments Name Boiler Type Unit Capacity Combustion Controls Post Combustion Control Sequence Bituminous Prairie State Generating Co.

Prairie State Generating Station Units 1 and 2 PC 750 MW ( each unit) Low NO x burners SCR ESP Wet FGD Scrubber Wet ESP Corn Belt Energy Corporation Prairie Energy Power Plant PC 91 MW Low NO x burners/ staged combustion SCR ESP Wet FGD Scrubber Indeck Elwood LLC ( Indeck) CFB 660 MW SNCR Lime Injection Fabric Filter Santee Cooper Power Cross Generating Station Units 3 and 4 PC 660 MW ( each unit) SCR ESP Wet FGD Scrubber Thoroughbred Generating Station Units 1 and 2 PC 750 MW ( each unit) Low NO x burners SCR ESP Wet FGD Scrubber Wet ESP Hugh L. Spurlock Power Station CFB 270 MW SNCR Lime Injection Fabric Filter Longview Power PC 600 MW Low NO x burners SCR Wet FGD Scrubber Fabric Filter Subbituminous MidAmerican Energy Co.

Council Bluffs Energy Center Unit 4 PC 790 MW Low NO x burners SCR Activated Carbon Injection Lime Spray Dryer Fabric Filter Sevier Power Company's NEVCO Energy CFB 270 MW SNCR Lime Injection Lime Spray Dryer Fabric Filter Burns a mixture of western bituminous / western ( non SRB) subbituminous coal Plum Point Energy Associates PC 550 800 MW SCR Wet FGD Scrubber Fabric Filter Bull Mountain Energy Roundup Power Plant Units 1 and 2 PC 390 MW ( each unit) Low NO x burners SCR Lime Spray Dryer PJ Fabric Filter Rocky Mountain Power Hardin Generation Project PC 113 MW SCR Lime Spray Dryer Fabric Filter City Utilities of Springfield Southwest Power Station Unit 2 PC 275 MW Low NO x burners SCR Activated Carbon Injection ( Note A) Lime Spray Dryer Fabric Filter Table 2 ( Continued)

Category Electric Utility Source Air Emission Control Configuration Comments Name Boiler Type Unit Capacity Combustion Controls Post Combustion Control Sequence 16 Tucson Electric Power Company Springerville Units 3 and 4 PC 400 MW ( each unit) Low NO x burners SCR Lime Spray Dryer Fabric Filter WE Energies Elm Road Generating Station PC 615 MW ( each unit) Low NO x burners SCR ESP Wet FGD Scrubber Wet ESP Wisconsin Public Service Corp.

Weston Plant PC 500 MW Low NO x burners SCR Activated Carbon Injection Lime Spray Dryer Fabric Filter Lignite Texas New Mexico Power Company TNP One Units 1and 2 CFB 175 MW ( each unit) Lime Injection Fabric Filter Alcoa's Rockdale Power Plant CFB 1and CFB 2 CFB 216.5 MW Net ( each unit) SNCR Lime Injection Fabric Filter IGCC No units of this design have been permitted Coal refuse Kentucky Mountain Power CFB 250 MW SCNR Lime Injection Fabric Filter EnviroPower of Illinois, LLC CFB 250 MW ( each unit) SNCR Lime Injection Fabric Filter Burns a mixture of bituminous coal refuse ( culm) and bituminous coal Note A. The entity building this plant decided to include as a part of this project the emissions associated with a potential Hg control system. The entity building this plant is anticipating controlling Hg emissions by means of injecting powdered activated carbon. However, a final decision as to the exact method of Hg control has not been made. The entity building this plant does plan on installing some type of Hg control, but is holding off making a final decision until a later date so that the most effective system of Hg control that has been shown to be compatible with the NO X, PM, and SO X pollution control technologies can be determined. If the Hg control is not powdered activated carbon, then it will be at least as effective. 17 Table 3. Summary of Mercury Emission Limitations for Coal Fired Electric Utility Steam Generating Units Category Electric Utility Source Emission Limits Comments Name Permit Hg Emissions Limitation Converted to input based Emissions Limitation Converted to output based Emissions Limitation Bituminous Prairie State Generating Co.

Prairie State Generating Station Units 1 and 2 Federal NESHAP limit NA NA No defined emission limit Corn Belt Energy Corporation Prairie Energy Power Plant 4 x 10 6 lb/ MMBtu heat input 4 lb/ TBtu 3.9 x 10 5 lb/ MWh A Indeck Elwood LLC ( Indeck) 2 x 10 6 lb/ MMBtu heat input 2 lb/ TBtu 2 x 10 5 lb/ MWh A Santee Cooper Power Cross Generating Station Units 3 and 4 3.6 x 10 6 lb/ MMBtu heat input 3.6 lb/ TBtu 3.5 x 10 5 lb/ MWh A Thoroughbred Generating Station Units 1 and 2 3.21 x 10 6 lb/ MMBtu heat input 3.21 lb/ TBtu 3.2 x 10 5 lb/ MWh A Hugh L. Spurlock Power Station 2.65 x 10 6 lb/ MMBtu heat input 2.65 lb/ TBtu 2.6 x 10 5 lb/ MWh A Longview Power 1.46 x 10 2 lb/ hr based on a 3 hour average and 6.38 x 10 2 TPY based on 12 month rolling average. 2.4 lb/ TBtu 2.3 x 10 5 lb/ MWh A, B Subbituminous MidAmerican Energy Co.

Council Bluffs Energy Center Unit 4 1.7 x 10 6 lb/ MM Btu heat input 1.7 lb/ TBtu 1.7 x 10 5 lb/ MWh A Sevier Power Company's NEVCO Energy 4 x 10 7 lb/ MM Btu heat input 0.4 lb/ TBtu 0.39 x 10 5 lb/ MWh A Plum Point Energy Associates 12.8 lb/ TBtu heat input 12.8 lb/ TBtu 12.6 x 10 5 lb/ MWh A Bull Mountain Energy Roundup Power Plant Units 1 and 2 3.23 x 10 6 lb/ MMBtu heat input 3.23 lb/ TBtu 3.2 x 10 5 lb/ MWh A Rocky Mountain Power Hardin Generation Project 5.8 lb/ TBtu heat input based on 1 hour average 5.8 lb/ T Btu 5.7 x 10 5 lb/ MWh A City Utilities of Springfield Southwest Power Station Unit 2 7.5 x 10 6 lb/ MMBtu heat input 7.5 lb/ TBtu 7.4 x 10 5 lb/ MWh A Table 3 ( Continued)

Category Electric Utility Source Emission Limits Comments Name Permit Hg Emissions Limitation Converted to input based Emissions Limitation Converted to output based Emissions Limitation 18 Tucson Electric Power Company Springerville Units 3 and 4 6.9 x 10 6 lb/ MMBtu heat input 6.9 lb/ TBtu 6.8 x 10 5 lb/ MWh A WE Energies Elm Road Generating Station 1.12 lb/ TBtu heat input in any 12 consecutive months 1.12 lb/ TBtu 1.1 x 10 5 lb/ MWh A Wisconsin Public Service Corp.

Weston Plant 1.7 lb/ TBtu heat input in any 12 consecutive months 1.7 lb/ TBtu 1.7 x 10 5 lb/ MWh A Lignite Texas New Mexico Power Company TNP One Units 1 and 2 Maximum Allowable Emission Rates 0.3 lb/ hr, 1.3 TPY 190 lb/ TBtu 186 x 10 5 lb/ MWh A, C, D Alcoa's Rockdale Power Plant CFB 1and CFB 2 Maximum Allowable Emission Rates 0.033 lb/ hr, 0.048 TPY 3.7 lb/ TBtu 3.6 x 10 5 lb/ MWh A, E IGCC No units of this design have been permitted 2 x 10 5 lb/ MWh F Coal refuse Kentucky Mountain Power 81 x 10 6 lb/ MMBtu heat input 81 lb/ TBtu 80 x 10 5 lb/ MWh A, G Coal refuse/ coal EnviroPower of Illinois, LLC 4 x 10 6 lb/ MMBtu heat input 4 lb/ TBtu 3.9 x 10 5 lb/ MWh A, H Notes:

A The emission limits were converted from input based standard ( lb/ TBtu) to output based standard ( lb/ MWh) by multiplying by 9.8 x 10 6. This factor incorporates a 35 percent efficiency is 10 joules per watt hour ( J/ Wh) ( 9,833 Btu per kilowatt hour ( kWh)).

B Based on a boiler capacity of 6,114 MMBtu/ hr. A permitted emission limit of 6.38 x 10 2 TPY * 2000 lb/ T / 8760 hr/ yr / 6,114 MMBtu/ hr = 2.4 x 10 6 lb/ MMBtu or 2.4 lb/ Tbtu. 2.4 lb/ Tbtu * 9.8 x 10 6 = 2.3 x10 5 lb/ MWh.

C Based on EPA ICR stack testing done on 10/ 6  10/ 8/ 99. While testing the coal feed averaged 234,897 lb/ hr. The heat content of the coal averaged 6670 Btu/ lb. 234,897 lb/ hr * 6670 Btu/ lb / 1,000,000 = 1,566.6 MMBtu/ hr. A permitted emission limit of 1.3 TPY * 2000 lb/ T / 8760 hr/ yr / 1,566.6 MMBtu/ hr = 1.90 x 10 4 lb/ MMBtu or 190 lb/ Tbtu. 190 lb/ Tbtu * 9.8 x 10 6 = 186 x10 5 lb/ MWh.

D This permit level predates the 1990 Amendments to the CAA so we would not give it much credence. There appear to be no other new or existing lignite fired units with a Hg emission limit.

E Based on a boiler capacity of 2,960 MMBtu/ hr. A permitted emission limit of 0.048 TPY * 2000 lb/ T / 8760 hr/ yr / 2,960 MMBtu/ hr = 3.7 x 10 6 lb/ MMBtu or 3.7 lb/ Tbtu. 3.7 lb/ Tbtu * 9.8 x 10 6 = 3.6 x10 5 lb/ MWh.

F The are currently no units of this design ( IGCC) have been permitted. However it is prudent to promulgate a new emissions limit. For this limit we used the ICR proposed emission limit data from the only two IGCC units in the country.

G This is a very high limit for a bituminous coal refuse ( culm) fired unit with this furnace type and these controls. We called Kentucky DEP and asked about the limit and they also noted it was very high and wondered why it hadn't been challenged.

H This unit is permitted to fire a mixture of waste bituminous ( culm) and bituminous coal therefore it is not strictly a coal refuse fired unit.


[Federal Register Volume 77, Number 29 (Monday, February 13, 2012)]
[Notices]
[Page 7620]
[FR Doc No: 2012-3220]

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SECURITIES AND EXCHANGE COMMISSION

Proposed Collection; Comment Request

Upon Written Request, Copies Available From: Securities and Exchange
Commission, Office of Investor Education and Advocacy, Washington, DC
20549-0213.

Extension:
    Form SE., OMB Control No. 3235-0327, SEC File No. 270-289.

    Notice is hereby given that, pursuant to the Paperwork Reduction
Act of 1995 (44 U.S.C. 3501 et seq.), the Securities and Exchange
Commission (``Commission'') is soliciting comments on the collection of
information summarized below. The Commission plans to submit this
existing collection of information to the Office of Management and
Budget for approval.
    Form SE (17 CFR 239.64) is used by registrants to file paper copies
of exhibits, reports or other documents that would be difficult or
impossible to submit electronically. The information contained in Form
SE is used by the Commission to identify paper copies of exhibits. Form
SE is filed by individuals, companies or other entities that are
required to file documents electronically. Approximately 50 registrants
file Form SE and it takes an estimated 0.10 hours per response for a
total annual burden of 5 hours.
    Written comments are invited on: (a) Whether this proposed
collection of information is necessary for the proper performance of
the functions of the agency, including whether the information will
have practical utility; (b) the accuracy of the agency's estimate of
the burden imposed by the collection of information; (c) ways to
enhance the quality, utility, and clarity of the information collected;
and (d) ways to minimize the burden of the collection of information on
respondents, including through the use of automated collection
techniques or other forms of information technology. Consideration will
be given to comments and suggestions submitted in writing within 60
days of this publication.
    Please direct your written comments to Thomas Bayer, Director/Chief
Information Officer, c/o Remi Pavlik-Simon, 6432 General Green Way,
Alexandria, Virginia 22312; or send an email to<EMAIL_ADDRESS>
    Dated: February 7, 2012.
Kevin M. O'Neill,
Deputy Secretary.
[FR Doc. 2012-3220 Filed 2-10-12; 8:45 am]
BILLING CODE 8011-01-P