[Federal Register Volume 84, Number 77 (Monday, April 22, 2019)]
[Notices]
[Page 16758]
[FR Doc No: 2019-08011]

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DEPARTMENT OF TRANSPORTATION

Federal Aviation Administration

[Docket No. FAA-2019-0291]

Agency Information Collection Activities: Requests for Comments;
Clearance of Renewed Approval of Information Collection: Notice of
Proposed Construction or Alteration, Notice of Actual Construction or
Alteration

AGENCY: Federal Aviation Administration (FAA), DOT.

ACTION: Notice and request for comments.

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SUMMARY: In accordance with the Paperwork Reduction Act of 1995, FAA
invites public comments about our intention to request the Office of
Management and Budget (OMB) approval to renew an information
collection. The FAA uses the information collected on form 7460-1 to
determine the effect a proposed construction or alteration would have
on air navigation and the National Airspace System (NAS) and the
information collected on form 7460-2 to measure the progress of actual
construction.

DATES: Written comments should be submitted by June 21, 2019.

ADDRESSES: Please send written comments:
    By Electronic Docket: www.regulations.gov (Enter docket number into
search field).
    By mail: Obstruction Evaluation Group, ATTN: Dave Maddox, Federal
Aviation Administration, 800 Independence Ave. SW, Room 400 East,
Washington, DC 20591.

FOR FURTHER INFORMATION CONTACT: Dave Maddox by email at:
[email protected]; phone:<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:
    Public Comments Invited: You are asked to comment on any aspect of
this information collection, including (a) whether the proposed
collection of information is necessary for FAA's performance; (b) the
accuracy of the estimated burden; (c) ways for FAA to enhance the
quality, utility and clarity of the information collection; and (d)
ways that the burden could be minimized without reducing the quality of
the collected information. The agency will summarize and/or include
your comments in the request for OMB's clearance of this information
collection.
    OMB Control Number: 2120-0001.
    Title: Notice of Proposed Construction or Alteration, Notice of
Actual Construction or Alteration.
    Form Numbers: FAA Forms 7460-1 and 7460-2.
    Type of Review: Renewal of an information collection.
    Background: 49 U.S.C Section 44718 states that the Secretary of
Transportation shall require notice of structures that may affect
navigable airspace, air commerce, or air capacity. These notice
requirements are contained in 14 CFR 77. The information is collected
via FAA Forms 7460-1 and 7460-2.
    Respondents: 85,000.
    Frequency: Information is collected on occasion.
    Estimated Average Burden per Response: Approximately 15 Minutes.
    Estimated Total Annual Burden: 70,075 hours.

    Issued in Washington, DC, on April 16, 2019.
Michael Helvey,
Manager, Obstruction Evaluation Group, AJV-15.
[FR Doc. 2019-08011 Filed 4-19-19; 8:45 am]
 BILLING CODE 4910-13-P


[Federal Register: April 9, 2008 (Volume 73, Number 69)]
[Notices]
[Page 19268-19269]
[DOCID:fr09ap08-89]

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SECURITIES AND EXCHANGE COMMISSION

Submission for OMB Review; Comment Request

Upon written request, copies available from: U.S. Securities and
Exchange Commission, Office of Investor Education and Advocacy,
Washington, DC 20549-0213.

Extension:
    Rule 17Ac3-1(a), SEC File No. 270-96, OMB Control No. 3235-0151;
Form TA-W (1669), SEC File No. 270-96, OMB Control No. 3235-0151.

    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'') has submitted to the Office of Management
and Budget requests for approval of extension on the following rule and
form: Rule 17Ac3-1(a) (17 CFR 240.17Ac3-1(a)) and Form TA-W (17 CFR
249b.101).
    Subsection (c)(4)(B) of Section 17A of the Securities Exchange Act
of 1934 (15 U.S.C. 78a et seq.) authorizes transfer agents registered
with an appropriate regulatory agency (``ARA'') to withdraw from
registration by filing with the ARA a written notice of withdrawal and
by agreeing to such terms and conditions as the ARA deems necessary or
appropriate in the public interest, for the protection of investors, or
in the furtherance of the purposes of Section 17A.
    In order to implement Section 17A(c)(4)(B) of the Exchange Act the
Commission, on September 1, 1977, promulgated Rule 17Ac3-1(a) and
accompanying Form TA-W. On January 11, 2007, the Commission amended
Rule 17Ac3-1(a) and accompanying Form TA-W to require that the form be
filed in electronic format on EDGAR. Rule 17Ac3-1(a) provides that
notice of withdrawal of registration as a transfer agent with the
Commission shall be filed on Form TA-W. Form TA-W requires the
withdrawing transfer agent to provide the Commission with certain
information, including: (1) The locations where transfer agent
activities are or were performed; (2) the reasons for ceasing the
performance of such activities; (3) disclosure of unsatisfied judgments
or liens; and (4) information regarding successor transfer agents.
    The Commission uses the information disclosed on Form TA-W to
determine whether the registered transfer agent applying for withdrawal
from registration as a transfer agent should be allowed to deregister
and, if so, whether the Commission should attach to the granting of the
application any terms or

conditions necessary or appropriate in the public interest, for the
protection of investors, or in furtherance of the purposes of Section
17A of the Exchange Act. Without Rule 17Ac3-1(a) and Form TA-W,
transfer agents registered with the Commission would not have a means
for voluntary deregistration when necessary or appropriate to do so.
    Respondents file approximately 50 TA-Ws with the Commission
annually. A Form TA-W filing occurs only once, when a transfer agent is
seeing deregistration. Since the form is simple and straightforward,
the Commission estimates that a transfer agent need spend no more than
30 minutes to complete a Form TA-W. Therefore, the total average annual
burden to covered entities is approximately 25 hours of preparation and
maintenance time.
    In view of the ready availability of the information requested by
Form TA-W, its short and simple presentation, and the Commission's
experience with the filers, we estimate that approximately 30 minutes
is required to complete Form TA-W, including clerical time.
Approximately 80 percent of these are completed by the transfer agent
or its employees and approximately 20 percent are completed by an
outside filing agent. In either case, we estimate a cost of
approximately $35 for each 30 minutes. Therefore, the total average
annual cost burden is approximately $1,750.
    Comments should be directed to (i) Desk Officer for the Securities
and Exchange Commission, Office of Information and Regulatory Affairs,
Office of Management and Budget, Room 10102, New Executive Office
Building, Washington, DC 20503 or by sending an e-mail to: Alexander--
<EMAIL_ADDRESS>and (ii) R. Corey Booth, Director/Chief
Information Officer, Securities and Exchange Commission, c/o Shirley
Martinson, 6432 General Green Way, Alexandria, VA 22312 or send an e-
mail to<EMAIL_ADDRESS>Comments must be submitted within 30
days of this notice.

    Dated: April 2, 2008.
Florence E. Harmon,
Deputy Secretary.
 [FR Doc. E8-7396 Filed 4-8-08; 8:45 am]

BILLING CODE 8011-01-P


[Federal Register Volume 84, Number 83 (Tuesday, April 30, 2019)]
[Notices]
[Pages 18293-18294]
[FR Doc No: 2019-08697]

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DEPARTMENT OF HOMELAND SECURITY

Federal Emergency Management Agency

[Docket ID FEMA-2019-0002; Internal Agency Docket No. FEMA-B-1926]

Changes in Flood Hazard Determinations

AGENCY: Federal Emergency Management Agency, DHS.

ACTION: Notice.

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SUMMARY: This notice lists communities where the addition or
modification of Base Flood Elevations (BFEs), base flood depths,
Special Flood Hazard Area (SFHA) boundaries or zone designations, or
the regulatory floodway (hereinafter referred to as flood hazard
determinations), as shown on the Flood Insurance Rate Maps (FIRMs), and
where applicable, in the supporting Flood Insurance Study (FIS)
reports, prepared by the Federal Emergency Management Agency (FEMA) for
each community, is appropriate because of new scientific or technical
data. The FIRM, and where applicable, portions of the FIS report, have
been revised to reflect these flood hazard determinations through
issuance of a Letter of Map Revision (LOMR), in accordance with Federal
Regulations. The LOMR will be used by insurance agents and others to
calculate appropriate flood insurance premium rates for new buildings
and the contents of those buildings. For rating purposes, the currently
effective community number is shown in the table below and must be used
for all new policies and renewals.

DATES: These flood hazard determinations will be finalized on the dates
listed in the table below and revise the FIRM panels and FIS report in
effect prior to this determination for the listed communities.
    From the date of the second publication of notification of these
changes in a newspaper of local circulation, any person has 90 days in
which to request through the community that the Deputy Associate
Administrator for Insurance and Mitigation reconsider the changes. The
flood hazard determination information may be changed during the 90-day
period.

ADDRESSES: The affected communities are listed in the table below.
Revised flood hazard information for each community is available for
inspection at both the online location and the respective community map
repository address listed in the table below. Additionally, the current
effective FIRM and FIS report for each community are accessible online
through the FEMA Map Service Center at https://msc.fema.gov for
comparison.
    Submit comments and/or appeals to the Chief Executive Officer of
the community as listed in the table below.

FOR FURTHER INFORMATION CONTACT: Rick Sacbibit, Chief, Engineering
Services Branch, Federal Insurance and Mitigation Administration, FEMA,
400 C Street SW, Washington, DC 20472,<PHONE_NUMBER>, or (email)
[email protected]; or visit the FEMA Map Information
eXchange (FMIX) online at https://www.floodmaps.fema.gov/fhm/fmx_main.html.

SUPPLEMENTARY INFORMATION: The specific flood hazard determinations are
not described for each community in this notice. However, the online
location and local community map repository address where the flood
hazard determination information is available for inspection is
provided.
    Any request for reconsideration of flood hazard determinations must
be submitted to the Chief Executive Officer of the community as listed
in the table below.
    The modifications are made pursuant to section 201 of the Flood
Disaster Protection Act of 1973, 42 U.S.C. 4105, and are in accordance
with the National Flood Insurance Act of 1968, 42 U.S.C. 4001 et seq.,
and with 44 CFR part 65.
    The FIRM and FIS report are the basis of the floodplain management
measures that the community is required either to adopt or to show
evidence of having in effect in order to qualify or remain qualified
for participation in the National Flood Insurance Program (NFIP).
    These flood hazard determinations, together with the floodplain
management criteria required by 44 CFR 60.3, are the minimum that are
required. They should not be construed to mean that the community must
change any existing ordinances that are more stringent in their
floodplain management requirements. The community may at any time enact
stricter requirements of its own or pursuant to policies established by
other Federal, State, or regional entities. The flood hazard
determinations are in accordance with 44 CFR 65.4.
    The affected communities are listed in the following table. Flood
hazard determination information for each community is available for
inspection at both the online location and the respective community map
repository address listed in the table below. Additionally, the current
effective FIRM and FIS report for each community are accessible online
through the FEMA Map Service Center at https://msc.fema.gov for
comparison.

(Catalog of Federal Domestic Assistance No. 97.022, ``Flood
Insurance.'')

Michael M. Grimm,
Assistant Administrator for Risk Management, Department of Homeland
Security, Federal Emergency Management Agency.

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                                                         Chief executive                         Online location of
        State and county           Location and case       officer of         Community map        letter of map       Date of modification   Community
                                          No.               community          repository             revision                                   No.
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Arizona: Pima...................  Town of Oro Valley   The Honorable Joe   Planning and        https://msc.fema.gov/  Aug. 6, 2019.........       040109
                                   (18-09-2032P).       Winfield, Mayor,    Zoning              portal/advanceSearch.
                                                        Town of Oro         Department, 11000
                                                        Valley, Town        North La
                                                        Hall, 11000 North   Ca[ntilde]ada
                                                        La Ca[ntilde]ada    Drive, Oro
                                                        Drive, Oro          Valley, AZ 85737.
                                                        Valley, AZ 85737.
Florida: St. Johns..............  Unincorporated       Mr. Paul M.         St. Johns County    https://msc.fema.gov/  Jul. 24, 2019........       125147
                                   Areas of St. Johns   Waldron, Chair,     Administration      portal/advanceSearch.
                                   County (19-04-       St. Johns County    Building, 4020
                                   0059P).              Board of            Lewis Speedway,
                                                        Commissioners,      St. Augustine, FL
                                                        500 San Sebastian   32085.
                                                        View, St.
                                                        Augustine, FL
                                                        32084.
Illinois:

    Cook........................  Village of Franklin  The Honorable       Village Hall, 9500  https://msc.fema.gov/  Aug. 2, 2019.........       170094
                                   Park (18-05-6092P).  Barrett F.          Belmont Avenue,     portal/advanceSearch.
                                                        Pedersen, Village   Franklin Park, IL
                                                        President,          60131.
                                                        Village of
                                                        Franklin Park,
                                                        9500 Belmont
                                                        Avenue, Franklin
                                                        Park, IL 60131.
    Will........................  Unincorporated       The Honorable       Land Use            https://msc.fema.gov/  Jul. 12, 2019........       170695
                                   Areas of Will        Lawrence M.         Department, 58      portal/advanceSearch.
                                   County (18-05-       Walsh, County       East Clinton
                                   5975P).              Executive, Will,    Street, Suite
                                                        County, Will        100, Joliet, IL
                                                        County Office       60432.
                                                        Building, 302
                                                        North Chicago
                                                        Street, Joliet,
                                                        IL 60432.
    Will........................  Village of           The Honorable John  Village Hall, 1050  https://msc.fema.gov/  Jul. 12, 2019........       170711
                                   Romeoville (18-05-   D. Noak, Mayor,     West Romeo Road,    portal/advanceSearch.
                                   5975P).              Village of          Romeoville, IL
                                                        Romeoville, 1050    60446.
                                                        West Romeo Road,
                                                        Romeoville, IL
                                                        60446.
Minnesota: Dakota...............  City of Lakeville    The Honorable       City Hall, 20195    https://msc.fema.gov/  Aug. 5, 2019.........       270107
                                   (18-05-4867P).       Douglas P.          Holyoke Avenue,     portal/advanceSearch.
                                                        Anderson, Mayor,    Lakeville, MN
                                                        City of             55044.
                                                        Lakeville, 20195
                                                        Holyoke Avenue,
                                                        Lakeville, MN
                                                        55044.
Nevada:
    Clark.......................  City of Las Vegas    The Honorable       Planning and        https://msc.fema.gov/  Aug. 1, 2019.........       325276
                                   (18-09-1695P).       Carolyn G.          Zoning              portal/advanceSearch.
                                                        Goodman, Mayor,     Department, 333
                                                        City of Las         North Rancho
                                                        Vegas, City Hall,   Drive, Las Vegas,
                                                        495 South Main      NV 89106.
                                                        Street, Las
                                                        Vegas, NV 89101.
    Clark.......................  Unincorporated       The Honorable       Clark County,       https://msc.fema.gov/  Aug. 1, 2019.........       320003
                                   Areas of Clark       Marilyn             Office of the       portal/advanceSearch.
                                   County (18-09-       Kirkpatrick,        Director of
                                   1695P).              Chair, Board of     Public Works, 500
                                                        Commissioners,      South Grand
                                                        Clark County, 500   Central Parkway,
                                                        South Grand         2nd Floor, Las
                                                        Central Parkway,    Vegas, NV 89155.
                                                        6th Floor, Las
                                                        Vegas, NV 89106.
New York: Rockland..............  Town of Clarkstown   The Honorable       Town Hall, 10       https://msc.fema.gov/  Sep. 27, 2019........       360679
                                   (19-02-0292P).       George Hoehmann,    Maple Avenue, New   portal/advanceSearch.
                                                        Supervisor, Town    City, NY 10956.
                                                        of Clarkstown,
                                                        Town Hall, 10
                                                        Maple Avenue, New
                                                        City, NY 10956.
Ohio: Franklin..................  City of Grove City   The Honorable       City Hall, 4035     https://msc.fema.gov/  Jul. 19, 2019........       390173
                                   (18-05-5403P).       Richard L. Stage,   Broadway, Grove     portal/advanceSearch.
                                                        Mayor, City of      City, OH 43123.
                                                        Grove City, City
                                                        Hall, 4035
                                                        Broadway, Grove
                                                        City, OH 43123.
Wisconsin:
    Kenosha.....................  City of Kenosha (18- The Honorable John  City Hall, 625      https://msc.fema.gov/  Jul. 17, 2019........       550209
                                   05-5192P).           M. Antaramian,      52nd Street,        portal/advanceSearch.
                                                        Mayor, City of      Kenosha, WI 53140.
                                                        Kenosha, City
                                                        Hall, 625 52nd
                                                        Street, Room 300,
                                                        Kenosha, WI 53140.
    Milwaukee...................  City of Milwaukee    The Honorable Tom   City Hall, 200      https://msc.fema.gov/  Aug. 2, 2019.........       550278
                                   (18-05-6243P).       Barrett, Mayor,     East Wells          portal/advanceSearch.
                                                        City of             Street,
                                                        Milwaukee, 200      Milwaukee, WI
                                                        East Wells          53202.
                                                        Street, Room 201,
                                                        Milwaukee, WI
                                                        53202.
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[FR Doc. 2019-08697 Filed 4-29-19; 8:45 am]
 BILLING CODE 9110-12-P


C 1 APPENDIX C PRELIMINARY ESTIMATES OF COSTS OF MERCURY EMISSION CONTROL TECHNOLOGIES FOR ELECTRIC UTILITY BOILERS Ravi K. Srivastava, Charles B. Sedman, and James D. Kilgroe U. S. Environmental Protection Agency National Risk Management Research Laboratory Research Triangle Park, NC 27711 As noted in Chapter 1 of this report, the U. S. Environmental Protection Agency ( EPA) has conducted an examination of the " co benefits" of potential pollution control options for the electric power industry to lower the emissions of its most significant air pollutants. One of these pollutants is mercury. The examination of the co benefits was conducted using the Integrated Planning Model ( IPM) [ 1]. For the co benefits study, this model had to be supplemented with information on performance and cost of mercury emission control technologies. Described in this appendix is the development of a preliminary assessment of performance and cost of mercury emission control technologies for utility boilers.

Behavior of Mercury in Combustion Systems In combustion systems, mercury is volatilized and converted to elemental mercury ( Hgo) in the high temperature regions of furnaces. As the flue gas is cooled, Hgo is oxidized to ionic forms of mercury ( Hg++). The rate of oxidization is dependent on the temperature, flue gas composition, and the properties and amount of fly ash and any entrained sorbents.

The time/ temperature profile within a combustion system determines the instantaneous equilibrium conditions, the kinetics of chemical reactions, and the time available for reactions. In incinerators the flue gas concentration of chlorine, in the form of hydrogen chloride ( HCl), is substantially higher than the concentration of Hgo. When the concentration of HCl is greater than the concentration of Hg, thermochemical calculations indicate that Hgo is preferentially converted to mercuric chloride ( HgCl2). In coal fired combustors, where the concentrations of HCl are much lower and where equilibrium conditions are not achieved, Hgo may be oxidized to mercury oxide ( HgO), mercury sulfate ( HgSO4), HgCl2, or some other form of mercury. The oxidization of Hgo to HgCl2 and other ionic forms of mercury is abetted by catalytic reactions on the surface of fly ash or sorbents that may be present in the flue gas.

Hg ° , HgCl2, and HgO are primarily in a vapor phase at flue gas cleaning temperatures, and special methods must be used for their capture. Each of these forms of mercury can be adsorbed onto porous solids such as fly ash, powdered activated carbon ( AC), and calcium based acid gas C 2 sorbents for subsequent collection in a particulate matter ( PM) control device. These mercury compounds can also be captured in carbon bed filters or other reactors containing appropriate sorbents. In the U. S., the control of mercury in municipal waste combustors ( MWCs) is based on the injection of powdered AC upstream of an electrostatic precipitator ( ESP) or a fabric filter ( FF).

HgCl2 is water soluble and readily reacts with alkali metal oxides in an acid base reaction; therefore, conventional acid gas scrubbers used for sulfur dioxide ( SO2) control can effectively capture HgCl2. Hgo is insoluble in water and must be adsorbed onto a sorbent or converted to a soluble form of mercury that can be collected by wet scrubbing. HgO has low solubility and probably has to be collected by methods similar to those used for Hgo.

Where scrubbers are already employed, mercury control is a function of the ratio of HgCl2 to total mercury concentrations in the flue gas  a ratio that is inherent to the properties of coal or other material being burned. The total mercury removal efficiency of scrubbers has been reported by the Electric Power Research Institute ( EPRI) and the Department of Energy ( DOE), to range from 30 to 90% [ 2]. Where scrubbers are not employed, activated carbon can be added upstream of the PM control device ( ESP or FF). While full scale tests have not yet been attempted, EPRI reports poor carbon utilization in tests with a pilot scale ESP installed on a flue gas slip stream from a coal fired utility boiler.

Status of Technologies for Control of Mercury Emissions A variety of air pollution control technologies are now commercially used to control mercury emissions from MWCs. In Europe these technologies include activated carbon injection ( ACI) followed by collection in a PM control device, the use of wet scrubbers, the use of carbon bed filters, and the use of reagents ( sodium sulfide or sodium tetrasulfide) to convert mercury into more easily captured forms. In the U. S., mercury emissions from MWCs are typically controlled by the use of ACI in conjunction with dry scrubbing systems. Few, if any, MWCs use wet scrubbers.

The control of mercury emissions from coal fired boilers is not commercially practiced in the U. S. The direct application of MWC mercury control technologies to coal fired boilers is difficult because of factors that make mercury more difficult and costly to capture:

  There is typically a higher fraction of Hg ° in the flue gas from coal fired boilers than in MWCs. This means that more effective sorbents must be developed for Hg ° capture or that Hg ° must be converted to more a easily captured form such as HgCl2.

  The concentration of mercury in coal fired utility flue gas is typically less that 10 µ g/ dscm while the concentration of mercury in MWCs may range from less the 200 to more than 1500 µ g/ dscm. As a consequence, the stack mercury concentrations of well controlled MWCs will typically be higher than the inlet mercury flue gas concentrations in coal fired utility boilers. C 3 The low mercury concentrations at the inlet to coal fired boiler air pollution control devices and the large volumes of flue gases that must be cleaned increase the difficulty and cost of control.

EPA, DOE, and EPRI are all engaged in research to develop more cost effective mercury control technologies for coal fired boilers. This includes research on mercury speciation, studies of mercury capture, and the development of improved control technologies.

Major objectives of these research efforts are to:

  Develop improved manual methods to measure mercury speciation in coal fired boilers and other combustion systems. Evaluate continuous emission monitors ( CEMs) that are being developed for measuring total and speciated mercury in flue gases. Effective CEMs can be used to monitor and adjust mercury control technology performance as well as serve as a compliance monitoring tool.

  Determine the factors that affect mercury speciation in flue gases and develop methods that can be used to control speciation in order to improve mercury capture.

  Develop more effective sorbents and reagents for mercury capture. More effective sorbents or reagents can be expected to accomplish one or more of the following goals: lower sorbent or reagent unit costs ($/ lb), increase sorbent collection efficiency or reagent reactivity, increase sorbent or reagent utilization rates, and provide more effective multi pollutant control.

  Evaluate and develop improved control technologies as embodied in more effective equipment or process conditions. For example: the use of additional ducting upstream of the PM control device to improve sorbent utilization through increased residence time, recycling of collected fly ash and sorbent into the flue gas upstream of the PM control device to increase sorbent utilization, and equipment modifications needed to inject a reagent into the flue gas to increase conversion of Hg ° to HgCl2 for collection in wet scrubbers.

It is believed that this research will develop improved technologies for controlling mercury emissions from coal fired boilers. While substantial progress is expected over the next several years, it is not now possible to quantify the improvements in performance and costs that will accrue from these efforts.

Control Technology Options Approximately 67% ( capacity basis) of the existing coal fired utility boilers in the U. S. are equipped only with ESPs for the control of PM. Another 7% employ ESPs followed by wet scrubbers. The remaining boilers employ dry scrubbers ( spray dryers and ESPs or FFs) or employ FFs for control of PM. C 4 In this study, model plants with eight different flue gas cleaning equipment configurations, called existing configurations, were used. In addition, it was assumed that each of the existing flue gas cleaning system configurations could be associated with a coal fired utility boiler that burns either bituminous or subbituminous coal  depending on the plant location. These 16 model plants, reflecting differences in flue gas cleaning equipment and type of coal burned, are shown in Exhibit C1.

Each retrofit option shown in Exhibit C1 was based on the use of ACI. This is the only technology for which there is pilot scale performance data for both eastern and western coals.

Two major performance parameters were selected for each retrofit option:

  The mercury collection efficiency across the air pollution control system, and   The ratio of the required carbon injection rate to mercury flow rate in the flue gas at the inlet to the first air pollution control device.

Mercury collection efficiencies in combustion systems, equipped only with ESPs or FFs, are affected by the concentration of mercury in the flue gas at the inlet to the PM control device, and the amount of mercury that is adsorbed onto the fly ash and subsequently removed in the PM control device. No attempt was made in this study to quantify the capture of adsorbed mercury on PM since there is only fragmentary information on this subject. Two assumptions were made on the effects of low mercury inlet concentrations in order to obtain reasonable mercury control retrofit costs.

In the EPA Mercury Study Report to Congress, the required mercury control efficiency for each retrofit option was assumed to be 90% [ 3]. In this study 90% control was assumed to be required for only those units whose existing equipment configuration includes wet scrubbers. Lower collection efficiencies were assumed for units that now employ ESPs, FFs, or dry scrubbers ( see Exhibit C1). An 85% collection efficiency was assumed for non FGD units that select some combination of ACI and FFs as the mercury control method. For the two cold side ESP cases that use SC + ACI as the retrofit option, collection efficiencies of 80 and 65 percent are assumed respectively for the plants that burn bituminous coal ( Case 1A) and subbituminous coal ( Case 1B).

Dropping the collection efficiency from 90 to 85, from 90 to 80, or from 90 to 65% will have a disproportionate effect on the amount of carbon needed. At high collection efficiencies, increasingly larger amounts of carbon are required for each percentage point in collection efficiency gain. For Case 1B, a plant with a cold side ESP that burns subbituminous coal, a combination of lower performance requirements ( 65% collection efficiency) and lower carbon/ mercury ratio ( 7,500) was selected because of the potentially lower mercury flue gas inlet concentrations associated with the combustion of subbituminous coals. C 5 Units equipped only with ESPs will be the most difficult to retrofit in a cost effective manner. Cost trade off studies indicated that the most cost effective retrofit option, for which pilot scale test data exist, is spray cooling ( SC) followed by carbon injection upstream of a new ( relatively small) FF installed downstream of the existing ESP.

It will be less difficult to effectively retrofit plants with existing configurations that consist of FFs, either with or without dry scrubbers. Activated carbon in the FF cake provides better gasparticle contact than an ESP, and the longer effective carbon residence times greatly improve sorbent utilization. This has been validated in full scale tests on MWCs and pilot scale tests on coal fired combustors. Field tests have shown that it takes two to three times more ACI to achieve the same performance on MWCs equipped with dry scrubbers and ESPs than with dry scrubbers and FFs [ 4].

It is anticipated that current research on wet scrubbers will result in improved performance through the use of reagents or catalysts to convert mercury to chemical forms that are soluble in aqueous based scrubbers. However, since there are no published pilot scale test data that confirm this hypothesis, it was assumed for this study that ACI is needed for facilities with existing wet scrubbers. For utilities with cold side ESPs, this will entail SC followed by ACI. In facilities with existing hot side ESPs, the installation of FF downstream of the existing ESP will also be required.

Described in the following sections is the development of the information shown in Exhibit C 1. This is followed by a description of the cost methodology that EPA adopted in this work. Finally, costs associated with each of the model plants of Exhibit C1 are provided.

Model Performance Parameters Based on the information in EPA's Mercury Study Report to Congress [ 3] and other published literature [ 2, 5 10], control technologies based on injection of AC into the flue gas appear to hold promise for reducing mercury emissions from utility boilers. EPA arrived at this determination by considering that: ( 1) ACI technologies have been applied successfully on MWCs; ( 2) information on results achieved in pilot scale ACI tests, conducted on coal fired utility boilers, is available in published literature; and ( 3) limited cost data are available for applications of ACI  based technologies on utility boilers.

As discussed below and summarized in Exhibit C1, the estimates of mercury emission reduction performance and associated carbon injection rates are based on reported pilot scale applications [ 6 10].

In arriving at the contents of Exhibit C1, six assumptions were made with respect to mercury control system hardware and performance. These assumptions are described below. C 6 1. The performance estimates presented in Exhibit C1 reflect the mercury emission reduction percent calculated using Reduction (%) = 100*( Emissionin  Emissionstack) / Emissionin ( 1)

where:

Emissionin = flue gas mercury concentration at the inlet to the first air pollution control device; and Emissionstack = mercury emission level at stack exhaust.

2. It is known that the type of coal fired in the boiler can influence the performance of mercury emission reduction technologies. Therefore, as shown in Exhibit C1, separate estimates of mercury emission reduction performance and carbon injection rate were determined for bituminous and subbituminous coals. As described in assumptions 4, 5, and 6, below, these estimates are based on published data [ 6 10].

3. In each of the technologies shown in Exhibit C1, the boiler flue gas is spray cooled before injection of AC. In general, the operating costs associated with use of AC comprise a significant portion of total costs for ACI based technologies. Since spray cooling of flue gas results in significantly reduced requirements of AC, this cooling was included in each of the technologies shown in Exhibit C1. Note that the capital costs associated with spray cooling equipment are independent of the degree of cooling needed, within the range of referenced applications. Note also that spray cooling is assumed to exist at boiler sites with dry scrubbers. Consequently, no additional SCs are needed in Cases 7A, 7B, 8A, and 8B.

4. The performance estimates for cases 1A, 1B, 5A, 5B, 7A, 7B, 8A, and 8B were interpolated from field pilot data in references [ 6 10], as described below.

Reference [ 6] describes AC injection application on a low sulfur, high chlorine, Eastern bituminous coal fired boiler served by parallel pilot ESP and pilot FF units. In this application: ( 1) with an ESP and gas cooling ( Case 1A), 80% mercury control was achieved at 55,000: 1 C/ Hg and ( 2) with a FF and gas cooling ( Case 5A), 90% mercury control was achieved at 40,000: 1 C/ Hg. The high chlorine content of coal was thought to be responsible for the poor carbon utilization. Reference [ 10] describes subsequent attempts to add lime with ACI upstream of the FF, which resulted in improved performance of ACI. In this application, using an FF ( Case 5A), 90% mercury control was achieved at 12,000: 1 C/ Hg. Interpolation of these results suggests that 85% mercury reduction may be achieved using C/ Hg of 10,000: 1 as shown in Exhibit C1. C 7 For the analyses, C/ Hg at 10,000: 1 was selected for Case 5A. Since no comparable data are available for Case 1A, the proportional improvement in ACI performance due to the removal of HCl by lime is assumed to hold for ESPs. Therefore, 75% improvement in AC utilization suggests that ESPs ( Case 1A) can achieve 80% Hg control at 15,000: 1 C/ Hg with hydrated lime assistance, or with no HCl present in the flue gas.

It is observed that the supplemental use of hydrated lime with ACI to enhance mercury capture will not negatively impact the estimated costs of control. Capital costs are already covered by the sorbent storage and injection system costs, and lime is relatively cheap compared to the AC that it may displace ( the cost of hydrated lime is about $ 85/ ton compared with $ 909/ ton for the AC used in this study). In addition, the use of hydrated lime will generate additional credits for the control of SO2 , SO3 and fine PM.

Reference [ 7] describes similar pilot ACI testing on low sulfur subbituminous coal. Using the results of this testing, mercury emission reduction performance and carbon requirements for Cases 1B and 5B were determined. In the tests with an ESP ( Case 1B), up to 74% mercury removal was achieved at a C/ Hg of < 10,000: 1. This suggests that an average of 65% mercury removal can be achieved at a C/ Hg of 7500: 1 with gas cooling ( Case 1B). Again in the tests with a FF ( Case 5B), 90% mercury removal was achieved at a C/ Hg of 10,000: 1. This suggests that an average of 85% mercury removal can be achieved at a C/ Hg of 6,000: 1 with gas cooling ( Case 5B). The improved carbon utilization achieved in subbituminous coal tests over the bituminous coal results provided above is thought to be directly related to high fly ash alkalinity and low chlorine content of subbituminous coal.

Reference [ 8] describes mercury removal using a pilot dry scrubber and ACI on a simulated flue gas with no chlorine and elemental mercury vapor present. AC removed essentially all of the mercury at a C/ Hg of 770 ( using iodine impregnated AC). Reference [ 9] describes mercury removal using wet and dry scrubbers on a midwestern coal in which the dominant form of mercury is known to be HgCl2. Mercury removals of 75 85% were observed using no ACI, where the HgCl2 behaved as an acid gas and was sequestered by the alkaline FGD sorbent. Assuming that 50% of the mercury in the typical coal flue gas is oxidized and that remaining is elemental mercury, it is judged that dry scrubbing will control 50% of the mercury in Eastern coals and 65% of the mercury in high alkalinity Western subbituminous coals. With ACI, 85% removal can be achieved on both types of coal, but the AC needed will vary from 3000: 1 C/ Hg on the alkaline ash coals with FF control ( Case 7B) up to 10,000: 1 C/ Hg on Eastern bituminous coal with ESP control ( Case 8A). Intermediate levels of AC addition   around 6,000: 1   were judged necessary for Cases 7A and 8B to achieve 85% control.

5. The performance and carbon requirements associated with Cases 2A and 2B are assumed to be identical to Cases 5A and 5B, respectively. This assumption is made because a FF is the PM control device in each of these cases. However, whereas in Cases 5A and 5B FFs C 8 exist at boiler sites, in Cases 2A and 2B small FFs are considered to be needed to collect AC.

6. If wet FGD is available at a boiler site in addition to an ACI based technology, then 90% mercury reduction is assumed to be available without any change in cost over the corresponding case without wet FGD. Thus, for example, costs for Cases 1A and 3A of Exhibit C1 would be identical but 90% reduction is available in Case 3A in contrast to 80% in Case 1A. Thus costs for Cases 3A, 3B, 4A, 4B, 6A, and 6B are identical to Cases 1A, 1B, 2A, 2B, 5A, and 5B, respectively, but 90% mercury removal is available in cases with wet FGD.

Based on the carbon injection rates shown in Exhibit C1, costs associated with the use of each of the ACI technologies were developed. Described in the ensuing paragraphs is the methodology used in arriving at these costs. C 9 Exhibit C1 Viable Mercury Emission Control Technologies for Utility Boilers Case Existing Coal Type Mercury Emission Reduction C/ Hg Equipment Equipment (%) ( g carbon / g Hg)

1A Cold ESP bituminous SC + ACI 80 15,000 1B Cold ESP subbituminous SC + ACI 65 7,500 2A Hot ESP bituminous SC + ACI + FF 85 10,000 2B Hot ESP subbituminous SC + ACI + FF 85 6,000 3A Cold ESP + FGD bituminous SC + ACI 90 15,000 3B Cold ESP + FGD subbituminous SC + ACI 90 7500 4A Hot ESP + FGD bituminous SC + ACI + FF 90 10,000 4B Hot ESP + FGD subbituminous SC + ACI + FF 90 6,000 5A FF bituminous SC + ACI 85 10,000 5B FF subbituminous SC + ACI 85 6,000 6A FF + wet FGD bituminous SC + ACI 90 10,000 6B FF + wet FGD subbituminous SC + ACI 90 6,000 7A DS + FF bituminous ACI 85 6,000 7B DS + FF subbituminous ACI 85 3,000 8A DS + ESP bituminous ACI 85 10,000 8B DS + ESP subbituminous ACI 85 6,000 Abbreviations:

ACI: activated carbon injection DS: dry scrubber ( either a spray dryer absorber/ particulate matter removal system or a dry alkali sorbent injection/ particulate matter removal system) ESP: electrostatic precipitator FGD: flue gas desulfurization system FF: fabric filter ( or baghouse) Hg: mercury SC: spray cooler C 10 Determination of Capital Costs ACI systems, FFs, and SCs are utilized in the ACI based technologies shown in Exhibit C 1. Some cost information on these hardware elements, in the context of ACI based technologies, is available in the EPA's Mercury Study Report to Congress [ 3] and a recent Department of Energy ( DOE) publication [ 11]. This cost information, pertinent to specific applications on boiler sizes of 100 and 975 MW, is shown in Exhibit C2.

Exhibit C2 Cost in $ s of Major Equipment Used in ACI based Technologies1 FF SC ACI System 100 MW 975 MW 100 MW 975 MW 100 MW 975 MW EPA2 1,813,479 12,978,750 258,627 2,993,796 109,448 109,448 DOE3 Same as EPA Same as EPA Same as EPA Same as EPA 257,000 2,231,000 DOE has reported that it examined EPA's cost estimates for FF and SC provided in refrence [ 3] and found them to be reasonable [ 11]. However, as described in reference [ 11], DOE appears to have conducted more detailed cost estimates for ACI systems. Accordingly, EPA's costs for FFs and SCs and DOE's costs for ACI systems were used to develop the capital cost functions for each of the ACI based technologies shown in Exhibit C 1. Note, however, that DOE used a carbon injection rate of 30,000 g of carbon/ g of mercury [ 11]. Therefore, the DOE ACI system costs were adjusted to correspond to the injection rates shown in Exhibit C 1.

The steps taken in calculating capital cost ($/ kW) of applying a specific ACI based technology on a specific boiler are shown in Exhibit C3.

1 The EPA and DOE costs presented in this table were based on the same model boilers. A description of these model boilers of sizes 100 MW and 975 MW can be found in references [ 3] and [ 11].

2 Per Appendix B of Volume VIII of the Mercury Study Report to Congress [ 3], purchased equipment costs for SC and ACI systems were based on vendor contacts reported in 1993 and FF costs were based on 1992 data. Accordingly, in this study, EPA's costs for SC and FF are considered to be in 1993 dollars.

3 Per the reference [ 11], DOE's costs are on 1989 basis. These costs were escalated to 1993 dollars using the inflator factor of 1.144003567. This inflator factor has been derived from the Economic Report of the President, Council of Economic Advisers, Feb 1998 [ 13]. C 11 Exhibit C3 Capital Cost Calculation Description Cost or Data Symbol Boiler size ( MW) MW1 Purchased equipment cost ($) PE Installation cost ($) 4 Inst = x* PE Indirect cost ($) 5 Ind = y* PE Total capital cost ($) TCC = PE + Inst + Ind Retrofit factor6 1.15 Total capital cost w/ retrofit ($) TC = 1.15* TCC Capital cost ($/ kW) CC = TC/( MW1* 1000)

For each of the ACI based technologies, capital costs ($/ kW) were calculated for model boiler sizes of 100 and 975 MW. These model boilers are described in the references [ 3] and [ 11]. The capital costs ($/ kW) obtained were used to develop the capital cost function relating ($/ kW) to boiler size ( MW). This function has the form C1 = C2 ( MW2/ MW1) a ( 2)

where:

C1 = capital cost ($/ kW) of ACI based technology installation at the first model boiler; C2 = capital cost ($/ kW) of ACI based technology installation at the second model boiler; MW1 = first model boiler size in MW; MW2 = second model boiler size in MW; and a = a scaling factor reflecting economy of scale.

Capital cost functions, expressed by Equation ( 2), were obtained for each of the ACI based technologies.

4 The values of the installation cost factor, x, used are identical to those used in the Mercury Study Report to Congress [ 3]. These values are: 0.34 for SC, 0.15 for ACI, and 0.72 for FF.

5 The values of the indirect cost factor, y, used are identical to those used in the Mercury Study Report to Congress [ 3]. These values are: 0.45 for SC, 0.30 for ACI, and 0.45 for FF.

6 A retrofit factor of 1.15 was included in the cost estimation procedure to account for more difficult retrofits. C 12 Determination of Annual Fixed Operation and Maintenance ( O& M) Costs Fixed O& M costs include costs related to maintenance requirements ( labor and materials); taxes, insurance, and administration; and capital recovery. Following the guidelines in the Electric Power Research Institute's Technical Assessment Guide [ 12], the annual cost of maintenance labor and materials, expressed in ($/ kW), is assumed to be 1.5% of the capital cost ($/ kW). The annual carrying charge used in the IPM model includes the effects of capital recovery as well as taxes and insurance. Note that, as mentioned in Chapter 2 of this report, administration costs were not modeled in this effort.

Determination of Annual Variable O& M Costs7 Variable O& M costs include labor charges, costs related to consumption of activated carbon and power, any incremental waste disposal cost, cost of operating materials ( water for SC), and overhead. Calculation of each of these is described below.

Labor cost: Both operating labor and supervisory labor are accounted for in the cost estimates. Following the information provided in reference [ 3], the labor rate is taken to be $ 12/ hr and supervisory labor costs total 15% of operating labor costs. Then for a capacity factor ( CF), labor cost is computed using Labor ( mills/ kWh) = 1.15*$ 12/ hr* CF* 8760 hr/ yr* 1000 mills/$ / ( MW* 1000 kW/ MW* 8760 hr/ yr* CF) ( 3)

Activated carbon cost: Based on recent information, 8 the cost of activated carbon is taken to be $ 1.00 per kg of activated carbon. Using this cost along with the flue gas flow, concentration of mercury in the flue gas, CF, and carbon injection rate, the cost of activated carbon consumption ( mills/ kWh) is determined for each model boiler application. An average of the costs for the model boiler applications is considered to be the carbon consumption cost ( mills/ kWh) for each of the ACI based technologies.

Power consumption cost: Power costs provided in reference [ 3] for model boiler applications were based on a unit power cost of 46 mills/ kWh and on a carbon injection rate of 460 g of carbon per g of mercury. For this work, the annual power consumption costs ($/ yr) provided in reference [ 3] were adjusted to reflect any change in carbon injection rate and a power cost of 19.4 mills/ kWh in 1993. The adjusted power consumption costs ($/ yr) were used to arrive at the 7 Note that although the Mercury Study Report to Congress [ 3] was released in December 1997, the cost data in this study, at least for equipment, appear to be pertinent to 1993 ( see footnote 2). As a conservative measure, for this study all of the cost data presented in [ 3] were assumed to be for the year 1993.

8 Personal communication between Charles Sedman and Jim Kilgroe of EPA and Anthony Licata of Licata Energy & Environmental Consultants, Inc., Yonkers, NY, December 14, 1998. C 13 power consumption cost ( mills/ kWh) for model boiler applications. The average of the costs for the model boiler applications is considered to be the carbon consumption cost ( mills/ kWh) for each of the ACI based technologies.

Disposal cost: Annual disposal costs ($/ yr) for the model boiler applications provided in reference [ 3] were adjusted to reflect any change in carbon injection rate and then were used to arrive at disposal costs expressed in mills/ kWh. The average of the costs for the model boiler applications is considered to be the carbon consumption cost ( mills/ kWh) for each of the ACI based technologies.

Operating materials cost: These costs for the various applications were taken from the Mercury Study Report to Congress [ 3].

Overhead: Following the information in reference [ 3], the overhead cost for each of the ACIbased technologies was taken to be 60% of the labor and maintenance costs.

Results The costs of the ACI based technologies, developed using the above methodology, are shown in Exhibits C 4 through C 13 at the end of this appendix.

Caveats The performance and cost estimates of the ACI based technologies presented in this appendix are considered to be preliminary for several reasons. First, the performance estimates and associated carbon requirements are based on relatively few data points that have been established in pilot scale tests. Factors that are known to affect adsorption of mercury on activated carbon are: speciation of mercury in flue gas, available residence time ( duct length), effect of flue gas and ash characteristics, and adequacy of mixing between flue gas and activated carbon. The effect of these factors may not be accounted for in the relatively few, pilot scale, data points that comprised the basis for this work. The research being conducted by EPA, DOE, and EPRI is expected to address these issues in the next few years. In addition to the technical issues surrounding the use of AC for mercury control, more accurate estimation of equipment costs is needed to better capture the economy of scale that would be expected. C 14 References 1. Analyzing Electric Power Generation Under CAAA, Office of Air and Radiation, U. S. Environmental Protection Agency, Washington, D. C., March 1998. Available at the web site www. epa. gov/ capi.

2. EPA Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Plants   Final Report to Congress, Volume 1, EPA 453R 98 004a ( NTIS PB98 131773), Office of Air Quality Planning and Standards, U. S. Environmental Protection Agency, Research Triangle Park, NC, February 1998.

3. Keating, M. H., et. al., Mercury Study Report to Congress, EPA 452/ R 97 003 ( NTIS PB98 124738), Office of Air Quality Planning and Standards and Office of Research and Development, U. S. Environmental Protection Agency, Research Triangle Park, NC, December 1997.

4. Kilgroe, J. D., Control of Dioxin, Furan, and Mercury Emissions from Municipal Waste Combustors, Journal of Hazardous Materials, 47 ( 1966) 163 194.

5. R. Chang and G. Offen, " Mercury Emission Control Technologies: An EPRI Synopsis," Power Engineering, November 1995.

6. Waugh, E., et al., " Mercury Control in Utility ESPs and Baghouses through Dry Carbon Based Sorbent Injection Pilot Scale Demonstration," in EPRI DOE EPA Combined Air Pollutant Control Symposium, Particulates and Air Toxics, Volume 3, EPRI TR 108683 V3, Electric Power Research Institute, Palo Alto, CA, August 1997.

7. Haythornthwaite, S., et al., " Demonstration of Dry Carbon Based Sorbent Injection for Mercury Control in Utility ESPs and Baghouses," in EPRI DOE EPA Combined Air Pollutant Control Symposium, Particulates and Air Toxics, Volume 3, EPRI TR 108683 V3, Electric Power Research Institute, Palo Alto, CA, August 1997.

8. Helfritch, D., P. Feldman, and S. Pass, " A Circulating Fluid Bed Fine Particulate and Mercury Control Concept," in EPRI DOE EPA Combined Air Pollutant Control Symposium, Particulates and Air Toxics, Volume 3, EPRI TR 108683 V3, Electric Power Research Institute, Palo Alto, CA, August 1997.

9. Redinger, K., et al., " Mercury Emissions Control in FGD Systems," in EPRI DOE EPA Combined Air Pollutant Control Symposium, Particulates and Air Toxics, Volume 3, EPRI TR 108683 V3, Electric Power Research Institute, Palo Alto, CA, August 1997. C 15 10. Waugh, E. G., et al., " Mercury Control on Coal Fired Flue Gas Using Dry Carbon Based Sorbent Injection: Pilot Scale Demonstration," presented at the 1998 Air & Waste Management Association Annual Meeting and Exhibition, San Diego, CA, June 1998.

11. Brown T., W. O'Dowd, R. Reuther, and D. Smith, " Control of Mercury Emissions from Coal Fired Power Plants: A Preliminary Cost Assessment," in Proceedings of the Conference on Air Quality, Mercury, Trace Elements, and Particulate Matter, Energy & Environmental Research Center, McLean, VA, December 1998.

12. Technical Assessment Guide, Volume 1: Electricity Supply   1993 ( Revision 7), EPRI TR 102276s Vol. 1 Rev. 7, Electric Power Research Institute, Palo Alto, CA, 1993.

13. Economic Report of the President, Council of Economic Advisers, February 1998. Available at the web site www. access. gpo. gov/ eop/. C 16 Exhibit C4 SC+ ACI + cold ESP with Bituminous Coal Case 1A: SC+ ACI + cold ESP with bituminous coal Data for 975 MW from Table B 12 in EPA's Report to Congress ( RTC) [ 3]

Data for SC+ ACI for 100 MW from Table B 11 in EPA's RTC[ 3]

Source Size ( MW) 975 100 RTC Capacity factor 0.65 0.65 RTC g carbon / g Hg 15000 15000 Based on published data Hg concentration ( µ g/ dscm) 10 10 RTC Flue gas flowrate ( dscm/ hr) 4050000 411000 RTC Carbon ($/ kg) 9 $ 0.89 $ 0.89 Capital Costs: 1993$

Spray cooling system ($) $ 2,993,796 $ 258,627 RTC, 1993 $ s Carbon injection system ($) 10 $ 1,276,136 $ 147,004 Purchased equipment, PE, ($) $ 4,269,932 $ 405,631 Installation ($) $ 1,209,311 $ 109,984 Indirect ($) $ 1,730,049 $ 160,483 Total capital cost ($) $ 7,209,292 $ 676,099 Retrofit factor 1.15 1.15 Total capital cost w/ retrofit ($) $ 8,290,686 $ 777,514 Total capital cost ($/ kW) $ 8.50 $ 7.78 Exponent =  0.04 Capital cost ($/ kW) = 8.50*( 975/ MW)^ 0.04 Annual O& M:

Maintenance ($/ kW Yr) 0.13 0.12 Maintenance ($/ kW Yr) = 0.13*( 975/ MW)^ 0.04 975 100 Formula Labor ($/ yr) $ 59,616 $ 49,680 RTC Labor ( mills/ kWh) = 0.01 0.09 Given below Carbon cost ($/ yr) $ 3,077,496 $ 312,309 RTC Carbon ( mills/ kWh) = 0.55 0.55 0.55 Power ($/ yr) $ 964,396 $ 88,921 RTC Power ( mills/ kWh) = 0.07 0.07 0.07 Disposal ($/ yr) $ 139,826 $ 94,630 RTC Disposal ( mills/ kWh) = 0.025 0.166 0.096 Operating materials ($/ yr) $ 219,572 $ 18,968 RTC Operating matls ( mills/ kWh) = 0.04 0.03 0.04 Overhead ( mills/ kWh) 0.02 0.06 Given below Labor varies with usage ( not with boiler size); overhead at 60% of labor & maintenance. Hence use:

Labor ( mills/ kWh) = 1.15* 12* CF* 8760* 1000 / MW* 1000* 8760* CF ( 1993$)

Overhead ( mills/ kWh) = 0.6 [ 1000/ 8760* fixed O& M($/ kW Yr) + labor( mills/ kWh)]

9 The carbon cost of $ 1.00/ kg, see footnote 8, has been deflated using a deflator of 0.8896797. The deflator was obtained using a 1997 to 1992 relationship from CEA, Economic Report of the President ( ERP), using February 1998 as a proxy for 1998 to 1993 relationship.

10 Carbon injection system costs were determined by adjusting the DOE costs, expressed in 1989 $ s, for carbon injection rate and escalating 1989 dollars to 1993 dollars using the inflation factor of 1.144003567. This inflation factor has been derived from CEA, ERP, 1993. C 17 Exhibit C5 SC+ ACI + Cold ESP with Subbituminous Coal Case 1B: SC+ ACI + cold ESP with subbituminous coal Data for 975 MW from Table B 12 in EPA's RTC [ 3]

Data for SC+ ACI for 100 MW from Table B 11 in EPA's RTC [ 3]

Source Size ( MW) 975 100 RTC Capacity factor 0.65 0.65 RTC g carbon / g Hg 7500 7500 Based on published data Hg concentration ( µ g/ dscm) 10 10 RTC Flue gas flowrate ( dscm/ hr) 4050000 411000 RTC Carbon ($/ kg) $ 0.89 $ 0.89 See footnote 9 Capital Costs: 1993$

Spray cooling system ($) $ 2,993,796 $ 258,627 RTC, 1993 $ s Carbon injection system ($) $ 638,068 $ 73,502 See footnote 10 Purchased equipment, PE, ($) $ 3,631,864 $ 332,129 Installation ($) $ 1,113,601 $ 98,959 Indirect ($) $ 1,538,629 $ 138,433 Total capital cost ($) $ 6,284,093 $ 569,521 Retrofit factor 1.15 1.15 Total capital cost w/ retrofit ($) $ 7,226,707 $ 654,949 Total capital cost ($/ kW) $ 7.41 $ 6.55 Exponent =  0.05 Capital cost ($/ kW) = 7.41*( 975/ MW)^ 0.05 Annual O& M:

Maintenance ($/ kW Yr) 0.11 0.10 Maintenance ($/ kW Yr) = 0.11*( 975/ MW)^ 0.05 975 100 Formula Labor ($/ yr) $ 59,616 $ 49,680 RTC Labor ( mills/ kWh) = 0.01 0.09 Given below Carbon cost ($/ yr) $ 1,538,748 $ 156,154 RTC Carbon ( mills/ kWh) = 0.28 0.27 0.28 Power ($/ yr) $ 961,379 $ 85,856 RTC Power ( mills/ kWh) = 0.07 0.06 0.07 Disposal ($/ yr) $ 69,913 $ 47,315 RTC Disposal ( mills/ kWh) = 0.013 0.083 0.048 Operating materials ($/ yr) $ 219,572 $ 18,968 RTC Operating matls ( mills/ kWh) = 0.04 0.03 0.04 Overhead ( mills/ kWh) 0.01 0.06 Given below Labor varies with usage ( not with boiler size); overhead at 60% of labor & maintenance. Hence use:

Labor ( mills/ kWh) = 1.15* 12* CF* 8760* 1000 / MW* 1000* 8760* CF Overhead ( mills/ kWh) = 0.6 [ 1000/ 8760* fixed O& M($/ kW Yr) + labor( mills/ kWh)] C 18 Exhibit C6 Hot ESP + SC+ ACI with Bituminous Coal Case 2A: Hot ESP + SC+ ACI + FF with bituminous coal Data from Tables B 10 and B 11, in EPA's RTC [ 3]

Source Size ( MW) 975 100 RTC Capacity factor 0.65 0.65 RTC g carbon / g Hg 10000 10000 Based on published data Hg concentration ( µ g/ dscm) 10 10 RTC Flue gas flowrate ( dscm/ hr) 4050000 411000 RTC Carbon ($/ kg) 0.89 0.89 See footnote 9 Capital Costs: 1993$

Spray cooling system ($) $ 2,993,796 $ 258,627 RTC, 1993 $ s Carbon injection system ($) $ 850,757 $ 98,003 See footnote 10 Fabric Filter ($) $ 12,978,750 $ 1,813,479 RTC, 1993 $ s Purchased equipment ($) $ 16,823,303 $ 2,170,109 Installation ($) $ 10,490,204 $ 1,408,339 Indirect ($) $ 7,442,873 $ 961,849 Total capital cost ($) $ 34,756,380 $ 4,540,296 Retrofit factor 1.15 1.15 Total capital cost w/ retrofit ($) $ 39,969,838 $ 5,221,340 Capital cost ($/ kW) $ 40.99 $ 52.21 Exponent = 0.11 Capital cost ($/ kW) = 40.99*( 975/ MW)^ 0.11 Annual O& M:

Maintenance ($/ kW Yr) 0.61 0.78 Maintenance ($/ kW Yr) 0.61*( 975/ MW)^ 0.11 975 100 Formula Labor ($/ yr) $ 238,464 $ 109,296 RTC Labor ( mills/ kWh) = 0.04 0.19 Given below Carbon cost ($/ yr) $ 2,051,664 $ 208,206 RTC Carbon ( mills/ kWh) = 0.37 0.37 0.37 Power ($/ yr) $ 2,050,797 $ 203,834 RTC Power ( mills/ kWh) = 0.16 0.15 0.15 Disposal ($/ yr) $ 621,152 $ 63,087 RTC Disposal ( mills/ kWh) = 0.112 0.111 0.111 Operating materials ($/ yr) $ 521,674 $ 79,785 RTC Operating matls ( mills/ kWh) = 0.09 0.14 Given below Overhead ( mills/ kWh) 0.07 0.17 Given below Labor and operating materials costs ( mills/ kWh) vary with boiler size; overhead at 60% of labor & maintenance. Hence use:

Labor ( mills/ kWh) = 1.15* 12* CF* 8760* 1000/ MW* 1000* 8760* CF Operating materials ( mills/ kWh) = ( 0.09 0.14)/ 875*( MW 100) + 0.14 Overhead ( mills/ kWh) = 0.6 [ 1000/ 8760* fixed O& M($/ kW Yr) + labor( mills/ kWh)] C 19 Exhibit C7 Hot ESP + SC+ ACI with Subbituminous Coal Case 2B: Hot ESP + SC+ ACI + FF with subbituminous coal Data from Tables B 10 and B 11, in EPA's RTC [ 3]

Source Size ( MW) 975 100 RTC Capacity factor 0.65 0.65 RTC g carbon / g Hg 6000 6000 Based on published data Hg concentration ( µ g/ dscm) 10 10 RTC Flue gas flowrate ( dscm/ hr) 4050000 411000 RTC Carbon ($/ kg) $ 0.89 $ 0.89 See footnote 9 Capital Costs: 1993$

Spray cooling system ($) $ 2,993,796 $ 258,627 RTC, 1993 $ s Carbon injection system ($) $ 510,454 $ 58,802 See footnote 10 Fabric Filter ($) $ 12,978,750 $ 1,813,479 RTC, 1993 $ s Purchased equipment ($) $ 16,483,000 $ 2,130,908 Installation ($) $ 10,439,159 $ 1,402,458 Indirect ($) $ 7,340,782 $ 950,088 Total capital cost ($) $ 34,262,941 $ 4,483,454 Retrofit factor 1.15 1.15 Total capital cost w/ retrofit ($) $ 39,402,382 $ 5,155,972 Capital cost ($/ kW) $ 40.41 $ 51.56 Exponent = 0.11 Capital cost ($/ kW) = 40.41*( 975/ MW)^ 0.11 Annual O& M:

Maintenance ($/ kW Yr) 0.61 0.77 Maintenance ($/ kW Yr) = 0.61*( 975/ MW)^ 0.11 975 100 Formula Labor ($/ yr) $ 238,464 $ 109,296 RTC Labor ( mills/ kWh) = 0.04 0.19 Given below Carbon cost ($/ yr) $ 1,230,998 $ 124,924 RTC Carbon ( mills/ kWh) = 0.22 0.22 0.22 Power ($/ yr) $ 2,049,188 $ 202,199 RTC Power ( mills/ kWh) = 0.16 0.15 0.15 Disposal ($/ yr) $ 372,691 $ 37,852 RTC Disposal ( mills/ kWh) = 0.067 0.066 0.067 Operating materials ($/ yr) $ 521,674 $ 79,785 RTC Operating matls ( mills/ kWh) = 0.09 0.14 Given below Overhead ( mills/ kWh) 0.07 0.17 Given below Labor and operating. materials. costs ( mills/ kWh) vary with boiler size; overhead at 60% of labor & maintenance. Hence use:

Labor ( mills/ kWh) = 1.15* 12* CF* 8760* 1000/ MW* 1000* 8760* CF Operating materials ( mills/ kWh) = ( 0.09 0.14)/ 875*( MW 100) + 0.14 Overhead ( mills/ kWh) = 0.6 [ 1000/ 8760* fixed O& M($/ kW Yr) + labor( mills/ kWh)] C 20 Exhibit C8 SC+ ACI + FF with Bituminous Coal Case 5A: SC+ ACI + FF with bituminous coal Using SC + ACI costs from Tables B 10 & B 11 in EPA's RTC [ 3]

Source Size ( MW) 975 100 RTC Capacity factor 0.65 0.65 RTC g carbon / g Hg 10000 10000 Based on published data Hg concentration ( µ g/ dscm) 10 10 RTC Flue gas flowrate ( dscm/ hr) 4050000 411000 RTC Carbon ($/ kg) $ 0.89 $ 0.89 See footnote 9 Capital Costs: 1993$

Spray cooling system ($) $ 2,993,796 $ 258,627 RTC, 1993 $ s Carbon injection system ($) $ 850,757 $ 98,003 See footnote 10 Purchased equipment, PE, ($) $ 3,844,553 $ 356,630 Installation ($) $ 1,145,504 $ 102,634 Indirect ($) $ 1,602,435 $ 145,783 Total capital cost ($) $ 6,592,493 $ 605,047 Retrofit factor 1.15 1.15 Total capital cost w/ retrofit ($) $ 7,581,367 $ 695,804 Total capital cost ($/ kW) $ 7.78 $ 6.96 Exponent =  0.05 Capital cost ($/ kW) = 7.78*( 975/ MW)^ 0.05 Annual O& M:

Maintenance ($/ kW Yr) 0.12 0.10 Maintenance ($/ kW Yr) = 0.12*( 975/ MW)^ 0.05 975 100 Formula Labor ($/ yr) $ 59,616 $ 49,680 RTC Labor ( mills/ kWh) = 0.01 0.09 Given below Carbon cost ($/ yr) $ 2,051,664 $ 208,206 RTC Carbon ( mills/ kWh) = 0.37 0.37 0.37 Power ($/ yr) $ 962,385 $ 86,878 RTC Power ( mills/ kWh) = 0.07 0.06 0.07 Disposal ($/ yr) $ 621,152 $ 63,087 RTC Disposal ( mills/ kWh) = 0.112 0.111 0.111 Operating materials ($/ yr) $ 219,572 $ 18,968 RTC Operating matls ( mills/ kWh) = 0.04 0.03 0.04 Overhead ( mills/ kWh) 0.014 0.059 Given below Labor varies with usage and not with boiler size; overhead at 60% of labor amd maintenance. Hence use:

Labor ( mills/ kWh) = 1.15* 12* CF* 8760* 1000 / MW* 1000* 8760* CF Overhead ( mills/ kWh) = 0.6 [ 1000/ 8760* fixed O& M($/ kW yr) + labor( mills/ kWh)] C 21 Exhibit C9 SC+ ACI + FF with Subbituminous Coal Case 5B: SC+ ACI + FF with subbituminous coal Using SC + ACI costs from Tables B 10 & B 11 in EPA's RTC [ 3]

Source Size ( MW) 975 100 RTC Capacity factor 0.65 0.65 RTC g carbon / g Hg 6000 6000 Based on Published data Hg concentration ( µ g/ dscm) 10 10 RTC Flue gas flowrate ( dscm/ hr) 4050000 411000 RTC Carbon ($/ kg) 0.89 0.89 See footnote 9 Capital Costs: 1993$

Spray cooling system ($) $ 2,993,796 $ 258,627 RTC, 1993 $ s Carbon injection system ($) $ 510,454 $ 58,802 See footnote 10 Purchased equipment, PE, ($) $ 3,504,250 $ 317,429 Installation ($) $ 1,094,459 $ 96,753 Indirect ($) $ 1,500,345 $ 134,023 Total capital cost ($) $ 6,099,054 $ 548,205 Retrofit factor 1.15 1.15 Total capital cost w/ retrofit ($) $ 7,013,912 $ 630,436 Total capital cost ($/ kW) $ 7.19 $ 6.30 Exponent =  0.06 Capital cost ($/ kW) = 7.19*( 975/ MW)^ 0.06 Annual O& M:

Maintenance ($/ kW Yr) 0.11 0.09 Maintenance ($/ kW Yr) = 0.11*( 975/ MW)^ 0.06 975 100 Formula Labor ($/ yr) $ 59,616 $ 49,680 RTC Labor ( mills/ kWh) = 0.01 0.09 Given below Carbon cost ($/ yr) $ 1,230,998 $ 124,924 RTC Carbon ( mills/ kWh) = 0.22 0.22 0.22 Power ($/ yr) $ 960,776 $ 85,243 RTC Power ( mills/ kWh) = 0.07 0.06 0.07 Disposal ($/ yr) $ 372,691 $ 37,852 RTC Disposal ( mills/ kWh) = 0.067 0.066 0.067 Operating materials ($/ yr) $ 219,572 $ 18,969 RTC Operating matls ( mills/ kWh) = 0.04 0.03 0.04 Overhead ( mills/ kWh) 0.014 0.059 Given below Labor varies with usage and not with boiler size; overhead at 60% of labor amd maintenance. Hence use:

Labor ( mills/ kWh) = 1.15* 12* CF* 8760* 1000 / MW* 1000* 8760* CF Overhead ( mills/ kWh) = 0.6 [ 1000/ 8760* fixed O& M($/ kW yr) + labor( mills/ kWh)] C 22 Exhibit C10 DS + ACI + FF with Bituminous Coal Case 7A: DS + ACI + FF with bituminous coal Taking only ACI costs from Tables B 10 & B 11 in EPA's RTC [ 3]

Source Size ( MW) 975 100 RTC Capacity factor 0.65 0.65 RTC g carbon / g Hg 6000 6000 Based on published data Hg concentration ( µ g/ dscm) 10 10 RTC Flue gas flowrate ( dscm/ hr) 4050000 411000 RTC Carbon ($/ kg) $ 0.89 $ 0.89 See footnote 9 Capital Costs: 1993$

Carbon injection system ($) $ 510,454 $ 58,802 See footnote 10 Purchased equipment ($) $ 510,454 $ 58,802 Installation ($) $ 76,568 $ 8,820 Indirect ($) $ 153,136 $ 17,641 Total capital cost ($) $ 740,159 $ 85,263 Retrofit factor 1.15 1.15 Total capital cost w/ retrofit ($) $ 851,183 $ 98,052 Capital cost ($/ kW) $ 0.87 $ 0.98 Exponent = 0.05 Capital cost ($/ kW) = 0.87*( 975/ MW)^ 0.05 Annual O& M:

Maintenance ($/ kW Yr) 0.013 0.015 Maintenance ($/ kW Yr) = 0.013*( 975/ MW)^ 0.05 975 100 Formula Labor ($/ yr) $ 29,808 $ 29,808 RTC Labor ( mills/ kWh) = 0.005 0.05 Given below Carbon cost ($/ yr) $ 1,230,998 $ 124,924 RTC Carbon ( mills/ kWh) = 0.22 0.22 0.22 Power ($/ yr) $ 2,413 $ 2,452 RTC Power ( mills/ kWh) = 0.00018 0.00182 0.00100 Disposal ($/ yr) $ 372,691 $ 37,852 RTC Disposal ( mills/ kWh) = 0.067 0.066 0.067 Operating materials ($/ yr) $ 0 $ 0 RTC Operating matls ( mills/ kWh) = 0.00 0.00 0.00 Overhead ( mills/ kWh) 0.004 0.032 Given below Labor varies with usage and not with boiler size; overhead at 60% of labor and maintenance. Hence use:

Labor ( mills/ kWh) = 1.15* 12* CF* 8760* 1000 / MW* 1000* 8760* CF Overhead ( mills/ kWh) = 0.6 [ 1000/ 8760* fixed O& M($/ kW yr) + labor( mills/ kWh)] C 23 Exhibit C11 DS + ACI + FF with Subbituminous Coal Case 7B: DS + ACI + FF with subbituminous coal Taking only ACI costs from Tables B 10 & B 11 in EPA's RTC [ 3]

Source Size ( MW) 975 100 RTC Capacity factor 0.65 0.65 RTC g carbon / g Hg 3000 3000 Based on published data Hg concentration ( µ g/ dscm) 10 10 RTC Flue gas flowrate ( dscm/ hr) 4050000 411000 RTC Carbon ($/ kg) $ 0.89 $ 0.89 See footnote 9 Capital Costs: 1993$

Carbon injection system ($) $ 255,227 $ 29,401 See footnote 10 Purchased equipment ($) $ 255,227 $ 29,401 Installation ($) $ 38,284 $ 4,410 Indirect ($) $ 76,568 $ 8,820 Total capital cost ($) $ 370,079 $ 42,631 Retrofit factor 1.15 1.15 Total capital cost w/ retrofit ($) $ 425,591 $ 49,026 Capital cost ($/ kW) $ 0.44 $ 0.49 Exponent = 0.05 Capital cost ($/ kW) = 0.44*( 975/ MW)^ 0.05 Annual O& M:

Maintenance ($/ kW Yr) 0.007 0.007 Maintenance ($/ kW Yr) = 0.007*( 975/ MW)^ 0.05 975 100 Formula Labor ($/ yr) $ 29,808 $ 29,808 RTC Labor ( mills/ kWh) = 0.005 0.05 Given below Carbon cost ($/ yr) $ 615,499 $ 62,462 RTC Carbon ( mills/ kWh) = 0.11 0.11 0.11 Power ($/ yr) $ 1,207 $ 1,226 RTC Power ( mills/ kWh) = 0.00009 0.00091 0.00050 Disposal ($/ yr) $ 186,346 $ 18,926 RTC Disposal ( mills/ kWh) = 0.034 0.033 0.033 Operating materials ($/ yr) $ 0 $ 0 RTC Operating matls ( mills/ kWh) = 0.00 0.00 0.00 Overhead ( mills/ kWh) 0.004 0.032 Given below Labor varies with usage and not with boiler size; overhead at 60% of labor and maintenance. Hence use:

Labor ( mills/ kWh) = 1.15* 12* CF* 8760* 1000 / MW* 1000* 8760* CF Overhead ( mills/ kWh) = 0.6 [ 1000/ 8760* fixed O& M($/ kW yr) + labor( mills/ kWh)] C 24 Exhibit C12 DS+ ACI + Cold ESP with Bituminous Coal Case 8A: DS+ ACI + cold ESP with bituminous coal Data for 975 MW from Table B 12 in EPA's Report to Congress [ 3]

Data for 100 MW from Table B 11 in EPA's Report to Congress [ 3]

Source Size ( MW) 975 100 RTC Capacity factor 0.65 0.65 RTC g carbon / g Hg 10000 10000 Based on published data Hg concentration ( µ g/ dscm) 10 10 RTC Flue gas flowrate ( dscm/ hr) 4050000 411000 RTC Carbon ($/ kg) $ 0.89 $ 0.89 See footnote 9 Capital Costs: 1993$ .

Carbon injection system ($) $ 850,757 $ 98,003 See footnote 10 Purchased equipment, PE, ($) $ 850,757 $ 98,003 Installation ($) $ 127,614 $ 14,700 Indirect ($) $ 255,227 $ 29,401 Total capital cost ($) $ 1,233,598 $ 142,104 Retrofit factor 1.15 1.15 Total capital cost w/ retrofit ($) $ 1,418,638 $ 163,420 Total capital cost ($/ kW) $ 1.46 $ 1.63 Exponent = 0.05 Capital cost ($/ kW) = 1.46*( 975/ MW)^ 0.05 Annual O& M:

Maintenance ($/ kW Yr) 0.02 0.02 Maintenance ($/ kW Yr) = 0.02*( 975/ MW)^ 0.05 975 100 Formula Labor ($/ yr) $ 29,808 $ 29,808 RTC Labor ( mills/ kWh) = 0.01 0.05 Given below Carbon cost ($/ yr) $ 2,051,664 $ 208,206 RTC Carbon ( mills/ kWh) = 0.37 0.37 0.37 Power ($/ yr) $ 4,022 $ 4,087 RTC Power ( mills/ kWh) = 3.1E 04 3.0E 03 1.7E 03 Disposal ($/ yr) $ 621,152 $ 63,087 RTC Disposal ( mills/ kWh) = 0.112 0.111 0.111 Operating materials ($/ yr) $ 0 $ 0 RTC Operating matls ( mills/ kWh) = 0.00 0.00 0.00 Overhead ( mills/ kWh) 0.005 0.033 Given below Labor varies with usage ( not with boiler size); overhead at 60% of labor & maintenance. Hence use:

Labor ( mills/ kWh) = 1.15* 12* CF* 8760* 1000 / MW* 1000* 8760* CF ( 1993$)

Overhead ( mills/ kWh) = 0.6 [ 1000/ 8760* fixed O& M($/ kW Yr) + labor( mills/ kWh)] C 25 Exhibit C13 DS+ ACI + Cold ESP with Subbituminous Coal Case 8B: DS+ ACI + cold ESP with subbituminous coal Data for 975 MW from Table B 12 in EPA's Report to Congress [ 3]

Data for SC+ ACI for 100 MW from Table B 11 in EPA's Report to Congress [ 3]

Source Size ( MW) 975 100 RTC Capacity factor 0.65 0.65 RTC g carbon / g Hg 6000 6000 Based on published data Hg concentration ( µ g/ dscm) 10 10 RTC Flue gas flowrate ( dscm/ hr) 4050000 411000 RTC Carbon ($/ kg) $ 0.89 $ 0.89 See footnote 9 Capital Costs: 1993$ .

Carbon injection system ($) $ 510,454 $ 58,802 See footnote 10 Purchased equipment, PE, ($) $ 510,454 $ 58,802 Installation ($) $ 76,568 $ 8,820 Indirect ($) $ 153,136 $ 17,641 Total capital cost ($) $ 740,159 $ 85,263 Retrofit factor 1.15 1.15 Total capital cost w/ retrofit ($) $ 851,183 $ 98,052 Total capital cost ($/ kW) $ 0.87 $ 0.98 Exponent = 0.05 Capital cost ($/ kW) = 0.87*( 975/ MW)^ 0.05 Annual O& M:

Maintenance ($/ kW Yr) 0.01 0.01 Maintenance ($/ kW Yr) = 0.01*( 975/ MW)^ 0.05 975 100 Formula Labor ($/ yr) $ 29,808 $ 29,808 RTC Labor ( mills/ kWh) = 0.01 0.05 Given below Carbon cost ($/ yr) $ 1,230,998 $ 124,924 RTC Carbon ( mills/ kWh) = 0.22 0.22 0.22 Power ($/ yr) $ 2,413 $ 2,452 RTC Power ( mills/ kWh) = 1.8E 04 1.8E 03 1.0E 03 Disposal ($/ yr) $ 372,691 $ 37,852 RTC Disposal ( mills/ kWh) = 0.067 0.066 0.067 Operating materials ($/ yr) $ 0 $ 0 RTC Operating matls ( mills/ kWh) = 0.00 0.00 0.00 Overhead ( mills/ kWh) 0.004 0.032 Given below Labor varies with usage ( not with boiler size); overhead at 60% of labor & maintenance. Hence use:

Labor ( mills/ kWh) = 1.15* 12* CF* 8760* 1000 / MW* 1000* 8760* CF Overhead ( mills/ kWh) = 0.6 [ 1000/ 8760* fixed O& M($/ kW Yr) + labor( mills/ kWh)]