[Federal Register Volume 78, Number 119 (Thursday, June 20, 2013)]
[Notices]
[Pages 37211-37212]
[FR Doc No: 2013-14732]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Project No. 459-313]

Union Electric Company (Ameren Missouri); Notice of Application
Accepted for Filing and Soliciting Comments, Motions To Intervene, and
Protests

    Take notice that the following hydroelectric application has been
filed with the Commission and is available for public inspection:
    a. Application Type: Non-Conforming Structures Report.
    b. Project No: 459-313.
    c. Date Filed: June 5, 2013, as supplemented June 12, 2013.
    d. Applicant: Union Electric Company (Ameren Missouri).
    e. Name of Project: Osage Hydroelectric Project.
    f. Location: The Osage Hydroelectric Project is located on the
Osage River in Benton, Camden, Miller, and Morgan counties, Missouri.
    g. Filed Pursuant to: Federal Power Act, 16 U.S.C. 791a--825r.
    h. Applicant Contact: Mr. Jeff Green, Shoreline Supervisor, Ameren
Missouri, P.O. Box 993, Lake Ozark, MO 65049,<PHONE_NUMBER>.
    i. FERC Contact: Shana High at<PHONE_NUMBER>, or email:
<EMAIL_ADDRESS>    j. Deadline for filing comments, motions to intervene, and
protests: July 15, 2013.
    All documents may be filed electronically via the Internet. See 18
CFR 385.2001(a)(1)(iii) and the instructions on the Commission's Web
site at http://www.ferc.gov/docs-filing/efiling.asp. Commenters can
submit brief comments up to 6,000 characters, without prior
registration, using the eComment system at http://www.ferc.gov/docs-filing/ecomment.asp. You must include your name and contact information
at the end of your comments. For assistance, please contact FERC Online
Support at<EMAIL_ADDRESS>or toll free at 1-866-208-3676,
or for TTY,<PHONE_NUMBER>. Although the Commission strongly encourages
electronic filing, documents may also be paper-filed. To paper-file,
mail an original and seven copies to: Secretary, Federal Energy
Regulatory Commission, 888 First Street NE., Washington, DC 20426.
Please include the project number (P-459-313) on any comments, motions,
or recommendations filed.
    The Commission's Rules of Practice and Procedure require all
intervenors filing documents with the Commission to serve a copy of
that document on each person whose name appears on the official service
list for the project. Further, if an intervenor files comments or
documents with the Commission relating to the merits of an issue that
may affect the responsibilities of a particular resource agency, they
must also serve a copy of the document on that resource agency.
    k. Description of Request: As required by the November 10, 2011
Order on Rehearing and Amending Shoreline Management Plan, ordering
paragraph (E)(2), Ameren filed its comprehensive report describing
encroachments (privately-built non-conforming structures) within the
revised project boundary. These encroachments are accessory structures
built after March 28, 2008, such as decks, walkways, gazebos, patios,
and boathouses, and do not include residential structures. The report
does not include structures built where owners had the right to
construct them, or those that have been previously permitted by Ameren
or its predecessors. The report only addresses unpermitted structures
built without authorization from Ameren and without an appropriate
property right. Ameren's report indicates that none of the
encroachments interfere with project purposes, and therefore no
structures will need to be removed.
    l. Locations of the Application: A copy of the application is
available for inspection and reproduction at the Commission's Public
Reference Room, located at 888 First Street NE., Room

2A, Washington, DC 20426, or by calling<PHONE_NUMBER>. This filing may
also be viewed on the Commission's Web site at 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. You may
also register online at http://www.ferc.gov/docs-filing/esubscription.asp to be notified via email of new filings and issuances
related to this or other pending projects. For assistance, call 1-866-
208-3676 or email<EMAIL_ADDRESS>for TTY, call (202) 502-
8659. A copy is also available for inspection and reproduction at
Ameren's shoreline office. Agencies may obtain copies of the
application directly from the applicant.
    m. Individuals desiring to be included on the Commission's mailing
list should so indicate by writing to the Secretary of the Commission.
    n. Comments, Protests, or Motions to Intervene: Anyone may submit
comments, a protest, or a motion to intervene in accordance with the
requirements of Rules of Practice and Procedure, 18 CFR 385.210, .211,
.214, respectively. In determining the appropriate action to take, the
Commission will consider all protests or other comments filed, but only
those who file a motion to intervene in accordance with the
Commission's Rules may become a party to the proceeding. Any comments,
protests, or motions to intervene must be received on or before the
specified comment date for the particular application.
    o. Filing and Service of Documents: Any filing must (1) bear in all
capital letters the title ``COMMENTS'', ``PROTEST'', or ``MOTION TO
INTERVENE'' as applicable; (2) set forth in the heading the name of the
applicant and the project number of the application to which the filing
responds; (3) furnish the name, address, and telephone number of the
person commenting, protesting or intervening; and (4) otherwise comply
with the requirements of 18 CFR 385.2001 through 385.2005. All
comments, motions to intervene, or protests must set forth their
evidentiary basis. Any filing made by an intervenor must be accompanied
by proof of service on all persons listed in the service list prepared
by the Commission in this proceeding, in accordance with 18 CFR
385.2010.

    Dated: June 13, 2013.
Kimberly D. Bose,
Secretary.
[FR Doc. 2013-14732 Filed 6-19-13; 8:45 am]
BILLING CODE 6717-01-P


[Federal Register Volume 84, Number 32 (Friday, February 15, 2019)]
[Notices]
[Pages 4570-4571]
[FR Doc No: 2019-02452]

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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-85105; File No. SR-ICC-2018-011]

Self-Regulatory Organizations; ICE Clear Credit LLC; Order
Approving Proposed Rule Change Relating to ICC's New Initiatives
Approval Policy and Procedural Framework

February 11, 2019.

I. Introduction

    On December 18, 2018, ICE Clear Credit LLC (``ICC'') filed with the
Securities and Exchange Commission (``Commission''), pursuant to
Section 19(b)(1) of the Securities Exchange Act of 1934 (``Act''),\1\ a
proposed rule change (SR-ICC-2018-011) to adopt a revised ICC New
Initiatives Approval Policy and Procedural Framework (``NIA Policy'').
The proposed rule change was published for comment in the Federal
Register on December 28, 2018.\2\ The Commission did not receive
comments on the proposed rule change. For the reasons discussed below,
the Commission is approving the proposed rule change.\3\
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    \1\ 15 U.S.C. 78s(b)(1).
    \2\ Securities Exchange Act Release No. 34-84889 (December 20,
2018), 83 FR 67445 (December 28, 2018) (SR-ICC-2018-011)
(``Notice'').
    \3\ Capitalized terms used herein but not otherwise defined have
the meaning set forth in the NIA Policy or the ICC rulebook, which
is available at https://www.theice.com/publicdocs/clear_credit/ICE_Clear_Credit_Rules.pdf.
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II. Description of the Proposed Rule Change

    ICC proposes to revise the NIA Policy, which sets forth ICC's
policies and procedures for the review and approval of certain new
initiatives to be offered or implemented by ICC.\4\ The NIA Policy
clarifies and harmonizes the policies, procedures, and documentation
for the review and approval of new initiatives that involve potentially
significant changes.\5\ The intention of the NIA Policy is to notify
all relevant departments of the introduction of the new initiative,
share information between departments, and establish requirements for
the pre-launch verification and testing of the new initiative.\6\
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    \4\ Notice, 83 FR at 67445.
    \5\ Id.
    \6\ Id.
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    New projects subject to the NIA policy are those that involve new
and material changes to the risk or pricing methodology, significant
changes to the processing system, significant changes to ICC rules,
significant changes to clearing operating procedures, material
modifications to significant capabilities provided by ICC, or
significant changes to models.\7\ A steering committee, comprised of
members of management, is responsible for prioritizing new initiatives
and guiding their implementation.\8\
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    \7\ Id.
    \8\ Id.
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    The New Initiative Approval Committee (``NIAC'') identifies,
reviews, and approves new initiatives and is a management committee
that includes department heads, and representatives from Enterprise
Risk, Quality Systems, and Systems Operations.\9\ The NIAC also
determines the conditions, restrictions, and limitations of new
initiatives.\10\ Additionally, the NIAC documents its process with an
approval matrix, risk assessment, a form verifying that all conditions
and restrictions have been satisfied prior to enactment of the new
initiative, and a tracking log for the identification and review of new
initiatives.\11\ The NIAC also reviews initiatives after implementation
to ensure compliance with any conditions.\12\ The chair of the NIAC
maintains the NIA Policy, ensures cooperation and coordination between
the steering committee and NIAC, and brings material changes to the NIA
Policy to the ICC board for review and approval.\13\
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    \9\ Id. at 67445-67446.
    \10\ Id. at 67446.
    \11\ Id.
    \12\ Id.
    \13\ Id.
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III. Discussion and Commission Findings

    Section 19(b)(2)(C) of the Act directs the Commission to approve a
proposed rule change of a self-regulatory organization if it finds that
such proposed rule change is consistent with the requirements of the
Act and the rules and regulations thereunder applicable to such
organization.\14\ For the reasons given below, the Commission finds
that the proposed rule change is consistent with Section 17A(b)(3)(F)
of the Act,\15\ and Rules 17Ad-22(d)(4) and (d)(8) thereunder.\16\
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    \14\ 15 U.S.C. 78s(b)(2)(C).
    \15\ 15 U.S.C. 78q-1(b)(3)(F).
    \16\ 17 CFR 240.17Ad-22(d)(4) and (d)(8).
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A. Consistency With Section 17A(b)(3)(F) of the Act

    Section 17A(b)(3)(F) of the Act requires, among other things, that
the rules of a registered clearing agency be designed to promote the
prompt and accurate clearance and settlement of securities transactions
and, to the extent applicable, derivative agreements, contracts and
transactions, and to assure the safeguarding of securities and funds
which are in the custody or control of the clearing agency or for which
it is responsible.\17\ As discussed above, the proposed rule change
would revise the NIA Policy, which sets forth, clarifies, and
harmonizes ICC's policies and procedures for approval of new
initiatives that involve potentially significant changes, including
initiatives that (1) involve new and material modifications to the risk
or pricing methodology; (2) involve potential significant changes to
the processing system, ICC Clearing Rules, or clearing operating
procedures; (3) involve new and material modifications to existing and
significant capabilities provided by ICC; or (4) involve Model Changes
\18\ classified as Materiality A under ICC's Model Validation Framework
\19\ (collectively, ``New Initiatives''). The Commission believes that,
if not clearly and consistently identified, reviewed, and approved
according to appropriate policies and procedures, such New Initiatives
could pose operational or other risks to ICC.
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    \17\ 15 U.S.C. 78q-1(b)(3)(F).
    \18\ Model Changes include new and enhanced risk modeling
components of ICC's risk management system. Depending on how
substantially the Model Change affects the system's assessment of
risk for the related risk driver(s), it is classified as Materiality
A (i.e., substantial impact) or Materiality B (i.e., no substantial
impact).
    \19\ Notice, 83 FR at 67445.
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    The NIA Policy would clearly describe and formalize the roles of
the key participants involved in identifying, reviewing, and ultimately
approving any such potentially significant New Initiatives, and
identify such participants' specific authority and responsibilities. It
also would identify, clearly describe, and formalize the specific steps
to be taken during the identification, review, and approval of New
Initiatives. By doing so, the Commission believes that the NIA Policy
will enhance ICC's ability to manage risks and avoid potential
disruptions to operations related to New Initiatives, thereby enhancing
ICC's ability to ensure the prompt and accurate clearance and
settlement of securities transactions. This, in turn, would enhance
ICC's ability to ensure it is in a better position to promptly clear
and settle securities transactions and assure the safeguarding of
securities and funds which are in the custody or control of ICC, or for
which it is responsible. Therefore, the Commission finds that the
proposed rule change is consistent with the requirements of Section
17A(b)(3)(F) of the Act.\20\
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    \20\ 15 U.S.C. 78q-1(b)(3)(F).

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B. Consistency With Rule 17Ad-22(d)(4)

    Rule 17Ad-22(d)(4) requires, in relevant part, that a registered
clearing agency that is not a covered clearing agency establish,
implement, maintain, and enforce written policies and procedures
reasonably designed to identify sources of operational risk and
minimize them through the development of appropriate systems, controls,
and procedures.\21\ The Commission believes that the NIA Policy would
do this through establishing revised and clarified definitions,
personnel responsibilities, and documentation procedures related to the
identification, review, and approval of New Initiatives.
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    \21\ 17 CFR 240.17Ad-22(d)(4).
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    Specifically, the revised NIA Policy would ensure that ICC's system
of approving New Initiatives defines such initiatives (as noted above)
as being those that most significantly impact key areas and functions
of ICC, and therefore helps ensures that ICC will appropriately
address, and therefore enhance its ability to mitigate, the potential
operational and other risks associated with implementing such New
Initiatives. Further, by clearly identifying and transparently
communicating the role of ICC's management across multiple departments
and functions, the Commission believes that the NIA Policy would
enhance ICC's ability to identify sources of operational risk by
involving the most relevant and responsible parties in focusing on the
most impactful initiatives.
    Additionally, the revisions to the NIA Policy would create a system
in which new initiatives would be assessed by relevant stakeholders
throughout ICC and through which such assessments would be documented.
For instance, the NIAC would utilize detailed matrixes and forms to
evidence that requisite approvals for new initiatives were obtained,
risks and mitigation plans were considered, and all appropriate
conditions were met prior to the implementation of a New Initiative.
The Commission believes that such documentation would enhance ICC's
ability to minimize operational risk by requiring thorough reviews and
justifications of its actions. As a result, the Commission finds that
the proposed rule, taken as a whole, enhances ICC's process of
identifying and minimizing sources of operational risk associated with
New Initiatives and is consequently consistent with Rule 17Ad-
22(d)(4).\22\
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    \22\ Id.
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C. Consistency With Rule 17Ad-22(d)(8)

    Rule 17Ad-22(d)(8) \23\ requires, in relevant part, that a
registered clearing agency that is not a covered clearing agency
implement, maintain and enforce written policies and procedures
reasonably designed to have governance arrangements that are clear and
transparent to fulfill the public interest requirements in Section 17A
of the Act.\24\ The NIA Policy proposed by ICC describes the roles of
key participants in the identification, review, approval, and
assessment of new initiatives. In particular, the NIA Policy describes
the steering committee's role in prioritizing the implementation of
initiatives as well as NIAC's role and composition, including the
participation of the heads of departments and representatives of
Enterprise Risk, Quality Systems, and Systems Operations. Additionally,
the proposal clarifies that the NIA Policy contains procedures for
notifying and seeking input from all relevant departments on the
introduction of New Initiatives. By setting forth clearly delineated
managerial roles and requiring information sharing across ICC related
to New Initiatives, the Commission finds that the proposed rule change
enhances and fosters governance arrangements that are clear and
transparent and is therefore consistent with the requirements of Rule
17Ad-22(d)(8).\25\
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    \23\ 17 CFR 240.17Ad-22(d)(8).
    \24\ 15 U.S.C. 78q-1.
    \25\ 17 CFR 240.17Ad-22(d)(8).
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IV. Conclusion

    On the basis of the foregoing, the Commission finds that the
proposed rule change is consistent with the requirements of the Act,
and in particular with the requirements of Section 17A of the Act \26\
and Rules 17Ad-22(d)(4) and 17Ad-22(d)(8) \27\ thereunder.
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    \26\ 15 U.S.C. 78q-1.
    \27\ 17 CFR 240.17Ad-22(d)(4) and (d)(8).
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    It is therefore ordered pursuant to Section 19(b)(2) of the Act
\28\ that the proposed rule change (SR-ICC-2018-011) be, and hereby is,
approved.\29\
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    \28\ 15 U.S.C. 78s(b)(2).
    \29\ In approving the proposed rule change, the Commission
considered the proposal's impact on efficiency, competition, and
capital formation. 15 U.S.C. 78c(f).
    \30\ 17 CFR 200.30-3(a)(12).

    For the Commission, by the Division of Trading and Markets,
pursuant to delegated authority.\30\
Eduardo A. Aleman,
Deputy Secretary.
[FR Doc. 2019-02452 Filed 2-14-19; 8:45 am]
BILLING CODE 8011-01-P


METHODOLOGY, ASSUMPTIONS, AND REFERENCES PRELIMINARY SO2 CONTROLS COST ESTIMATES FOR INDUSTRIAL BOILERS By Sikander Khan Environmental Engineer, U. S. EPA OCTOBER NOVEMBER 2003 Preliminary SO2 Controls Cost Estimates 2 COST ESTIMATES FOR SO2 CONTROLS INDUSTRIAL BOILERS 1.0 METHODOLOGY The cost estimates covered in this report were developed as part of the investigations conducted for the proposed Interstate Air Quality Rule ( IAQR) for industrial boilers. These costs are preliminary and are being reviewed further by the EPA.

The costs were developed for three boiler sizes, with heat inputs of 100, 250, and 1,000 MMBtu/ hr. The following SO2 control technologies were included in these estimates for coal and oil fired boilers, as indicated below:

In duct dry sorbent injection ( coal only) Spray Dryer Absorber ( coal only) Wet Flue Gas Desulfurization ( coal and oil)

It is to be noted that the purpose of this evaluation was to develop cost information for a large range of industrial boiler sizes and associated SO2 technologies. The decision on the use of this information in the proposed IAQR will be made as part of the Rule itself.

The methodology can be divided into two major activities: 1) Developing design basis for each SO2 control system and determining its operating impacts on the boiler performance and 2) determining capital and operating costs associated with retrofitting the SO2 control system. These two activities, along with the associated assumptions and references, are described below.

2.0 DESIGN BASIS AND PERFORMANCE IMPACTS Boiler combustion calculations were performed using standard procedures( 1,2), for the three boiler sizes of 100, 250, and 1,000 MMBtu/ hr. These calculations were performed for boilers firing coal and oil with various sulfur contents, which were selected based on coal sulfur data available from the EPA databases ( see Attachment 1). Tables included in this report list key data determined from these calculations for the three boilers firing coal and oil. These data were used to develop the design parameters and plant performance impacts for each SO2 control technology, as discussed below:

2.1 In duct Dry Sorbent Injection ( IDIS)

The design parameters and plant performance impacts for the IDIS system were established based on the criteria provided in a US Department of Energy ( DOE) design handbook( 3), which lists detailed process design and engineering guidelines for this technology. These estimates were developed for coal fired boilers only. The following key factors and assumptions were used: Preliminary SO2 Controls Cost Estimates 3 1. A SO2 reduction efficiency of 40 percent was used for each boiler application ( higher reduction rates are possible, as per the above handbook).

2. No waste recycling was used.

3. The reagent used was lime, which required provision of a hydrator for each boiler application.

4. It was assumed that the solid waste generated would be disposed off in a landfill.

5. It was assumed that the existing ash handling system could not handle the increased solid ash generated with the IDIS system, requiring an extension of this system .

6. The existing particulate control technology was assumed to be a precipitator.

The design parameters and plant performance impacts associated with the use of IDIS system are presented in Table 1. These impacts were used for the estimation of operating costs resulting from the use of this technology.

2.2 Spray Dryer Absorber ( SDA)

The design parameters and plant performance impacts for the SDA system were established based on the criteria taken from various sources( 4 7), which list detailed process design and engineering guidelines for this technology. These estimates were developed for coal fired boilers only. The following key factors and assumptions were used:

1. A SO2 reduction efficiency of 90% was used, based on industry data supporting this level of reduction( 5,6) ( see Attachment 2).

2. No waste recycle is used.

3. The existing particulate control technology was assumed to be a precipitator.

4. It was assumed that the solid waste generated would be disposed off in a landfill.

5. Auxiliary power was assumed to be 0.7 percent of the boiler's equivalent power generation capability.

The design parameters and plant performance impacts associated with the use of SDA system are presented in Table 2. These impacts were used for the estimation of operating costs resulting from the use of this technology.

2.3 Wet Flue Gas Desulfurization ( WFGD)

The design parameters and plant performance impacts for the WFGD system were established based on the criteria taken from various sources( 5 9), which list detailed process design and engineering guidelines for this technology. These estimates were Preliminary SO2 Controls Cost Estimates 4 developed for coal fired boilers only. The following key factors and assumptions were used:

1. A SO2 reduction efficiency of 90% was used, based on industry data supporting this level of reduction( 5,6) ( see Attachment 2).

2. The reagent was assumed to be limestone.

3. It was assumed that the solid waste generated would be disposed off in a landfill.

4. Auxiliary power was assumed to be 2.0 percent of the boiler's equivalent power generation capability.

The design parameters and plant performance impacts associated with the use of WFGD system are presented in Tables 3 and 4 for coal and oil fuels, respectively. These impacts were used for the estimation of operating costs resulting from the use of this technology.

3.0 CAPITAL AND LEVELIZED COSTS The capital costs ($/ MMBtu/ hr) for the IDIS system were developed using information from the aforementioned DOE design handbook( 3). For the SDA and WFGD systems budgetary cost estimates were obtained from vendors ( see Attachments 3 and 4). The balance of plant costs were developed using information from the EPA ` s CueCost Program( 5). A US Department of Commerce, Bureau of Economic Analysis( 10) price index was used to adjust cost basis from one year to another. The costs are based on 1999 dollars.

In general, an EPRI methodology( 11) was used for the above cost estimates, with the following cost factors used for the non process costs:

General Facilities: 5.0 % of total direct process cost Engineering and home office fees: 10% of total direct process cost Process contingency: 5.0% of total direct process cost Project contingency: 15% of total direct process and the above three non process costs Retrofit factor: 30% Preproduction cost: 2.0% of total plant investment with retrofit costs Inventory capital: cost for a 30 day reagent storage The capital costs for various SO2 technology applications are provided in Tables 5 through 8. It is to be noted that the budgetary costs obtained from the vendors were adjusted for the gas flow for the SDA system and for the items described in Attachment 4 for the WFGD system. A conservative retrofit factor of 30 percent was used to account for the expected difficulty of retrofitting the FGD equipment in an existing plant setting Preliminary SO2 Controls Cost Estimates 5 and certain modifications required to the existing plant equipment and structures that are not included in the estimates.

The levelized costs ($/ ton of SO2 removed) were calculated using the estimates of the capital costs and increased consumable rates associated with each technology, as shown in Tables 1 through 4. The economic factors used in these calculations( 1 4) were as follows:

Lime, $/ ton 50 Limestone, $/ ton 15 Water, $/ gal 0.0006 Solid waste disposal, $/ ton 12 Operator cost, $/ hr 30 Useful life, years 30 Carrying charges, % 12.00 Levelization factor 1.0 Maintenance cost (% of capital cost) 3.0 ( for WFGD) 2.0 ( for SDA and IDIS)

The levelized costs for various technology retrofits are presented in Table 9.

3.1 Sensitivity Cases Two sensitivity cases were evaluated to see the effect of changes in the study data and assumptions on the technology costs: 1) increased cost of power from 25 mills/ kwh to 50 mills/ kwh and 2) an increase of 20 percent in the technology capital cost. Only a few retrofit options ( IDSI on high sulfur coal, SDA, and WFGD on high sulfur coal) were evaluated to see the impact of these changes   the impact on other options should be similar. Table 10 presents the results. A comparison of Table10 and the corresponding values in Table 9 shows that:

1. Increase in the cost of power has a relatively small impact that includes:

  an increase of 0.8 to 4.5 percent of the levelized cost for the IDSI technology   an increase of 0.2 to 2.6 percent of the levelized cost for the SDA technology   an increase of 0.57 to 5.1 percent of the levelized cost for the WFGD technology 2. Increase in the capital cost has the following impacts:

  an increase of 11.5 to 17.7 percent of the levelized cost for the SDA technology   an increase of 13.9 to 17.3 percent of the levelized cost for the WFGD technology It is to be noted that, even with an increase of 20 percent in the capital cost, the levelized costs ($/ ton of SO2) remain below $ 1,500 for plant capacity factors of 50 percent and higher. Preliminary SO2 Controls Cost Estimates 6 5.0 REFERENCES 1. " Steam Its Generation and Use," Babcock and Wilcox, 40th Edition 2. " Power Test Code   Steam Generating Units," ASME PTC 4.1, 1991 3. " Duct Injection for SO2 Control Design Handbook," By Raytheon Engineers and Constructors, B& W, Energy and Environmental Research Center for U. S. DOE, Agreement DE AC22 88PC88852 4. " Spray Dryer Flue Gas Cleaning System Handbook," By Argonne National Laboratory for U. S. DOE, ANL/ ESD 7, April 1988 5. " Coal Utility Environmental Cost ( CUECost) Workbook User's Manual, Version 1.0," EPA 600/ R 99 056 ( NTIS PB99 151938), June 1999 6. " EPA Modeling Application Using The Integrated Planning Model,", http:// www. epa. gov/ airmarkets/ epa ipm/ index. html 7. R. Srivastava, et. al., " Flue Gas Desulfurization: The State of the Art," Journal of the Air & Waste Management Association, Volume 51, December 2001 8. " Limestone FGD Scrubbers: Users Handbook," By PEDCO Environmental, Inc. for U. S. EPA, EPA 600/ 8 81 017 9. E. Rubin, et. al., " New Models For FGD Performance, Cost And Hazardous Air Pollutant Removal," 1995 SO2 Control Symposium, Miami, Florida, March 28 31, 1995 10. " Implicit Price Deflator," Table 7.3. Quantity and Price Indexes, http:// www. bea. doc. gov/ bea/ dn/ nipaweb/ TableViewFixed. asp 11. " Technical Assessment Guide, Vol. I: Electricity Suppl 1993 ( Revision 7); EPRI TR 102276s; Electric Power Research Institute Preliminary SO2 Controls Cost Estimates 7 TABLE 1 DESIGN PARAMETERS AND PERFORMANCE IMPACTS FOR IN DUCT DRY SORBENT INJECTION High Sulfur Coal Lower Sulfur Coal Parameter Boiler   100 MMBtu/ hr Boiler   250 MMBtu/ hr Boiler   1000 MMBtu/ hr Boiler   100 MMBtu/ hr Boiler   250 MMBtu/ hr Boiler   1000 MMBtu/ hr Fuel sulfur, wt. % 3.43 3.43 3.43 2.0 2.0 2.0 Fuel ash, wt. % 12.71 12.71 12.71 13.2 13.2 13.2 Fuel heating value, Btu/ lb 11,922 11,922 11,922 11,922 11,922 11,922 Fly ash as % of total ash 90 90 90 90 90 90 CaO in lime, % 90 90 90 90 90 90 Flue gas flow, acfm 38,230 95,400 381,000 35,800 89,300 356,700 Flue gas temperature, oF 330 330 330 285 285 285 Approach to saturation, oF 40 40 40 40 40 40 Reagent recycle ( yes or no) No No No No No No Ca/ S ratio 2.4 2.4 2.4 2.4 2.4 2.4 Lime required, lb/ hr 1,301 3,253 13,010 759 1,897 7,586 Water required, gpm 10 25 98 7 17 70 Waste produced, ton/ hr 0.97 2.43 9.71 0.57 1.42 5.66 Auxiliary power required, kW 133 333 1,333 94 234 1,011 Additional operating labor, hr/ yr 2190 2190 2190 2190 2190 2190 Preliminary SO2 Controls Cost Estimates 8 TABLE 2 DESIGN PARAMETERS AND PERFORMANCE IMPACTS FOR SPRAY DRYER ABSORBER Coal Parameter Boiler   100 MMBtu/ hr Boiler   250 MMBtu/ hr Boiler   1000 MMBtu/ hr Fuel sulfur, wt. % 1.8 1.8 1.8 Fuel ash, wt. % 13.2 13.2 13.2 Fuel heating value, Btu/ lb 9000 9000 9000 Fly ash as % of total ash 90 90 90 CaO in lime, % 90 90 90 Flue gas flow, acfm 36,516 91,086 363,834 Flue gas temperature, oF 285 285 285 Existing particulate control type ESP ESP ESP Approach to saturation, oF 40 40 40 Reagent recycle ( yes or no) No No No Lime required, lb/ hr 710 1,776 7,103 Water required, gpm 6 14 56 Waste produced, ton/ hr 0.67 1.68 6.72 Auxiliary power required, kW 70 175 700 Additional operating labor, hr/ yr 2190 2920 4380 Preliminary SO2 Controls Cost Estimates 9 TABLE 3 DESIGN PARAMETERS AND PERFORMANCE IMPACTS FOR WET FLUE GAS DESULFURIZATION   FOR COAL High Sulfur Coal Lower Sulfur Coal Parameter Boiler   100 MMBtu/ hr Boiler   250 MMBtu/ hr Boiler   1000 MMBtu/ hr Boiler   100 MMBtu/ hr Boiler   250 MMBtu/ hr Boiler   1000 MMBtu/ hr Fuel sulfur, wt. % 3.43 3.43 3.43 2.5 2.5 2.5 Fuel ash, wt. % 12.71 12.71 12.71 12.71 12.71 12.71 Fuel heating value, Btu/ lb 11,922 11,922 11,922 11,922 11,922 11,922 Flue gas flow, acfm 38,230 95,400 381,000 38,230 95,400 381,000 Flue gas temperature, oF 330 330 330 330 330 330 Limestone required, lb/ hr 947 2,367 9,464 689 1,723 6,898 Water required, gpm 13 32 127 12 31 124 Waste produced, ton/ hr 0.81 2.0 8.1 0.59 1.5 5.9 Auxiliary power required, kW 200 500 2,000 200 500 2,000 Additional operating labor, hr/ yr 4,160 8,320 18,720 4,160 8,320 18,720 Preliminary SO2 Controls Cost Estimates 10 TABLE 4 DESIGN PARAMETERS AND PERFORMANCE IMPACTS FOR WET FLUE GAS DESULFURIZATION   FOR OIL Oil Parameter Boiler   100 MMBtu/ hr Boiler   250 MMBtu/ hr Boiler   1000 MMBtu/ hr Fuel sulfur, wt. % 2.18 2.18 2.18 Fuel ash, wt. % 0.06 0.06 0.06 Fuel heating value, Btu/ lb 18,268 18,268 18,268 Flue gas flow, acfm 41,100 102,600 371,100 Flue gas temperature, oF 480 480 344 Limestone required, lb/ hr 393 983 3,931 Water required, gpm 18 46 120 Waste produced, ton/ hr 0.34 0.84 3.4 Auxiliary power required, kW 200 500 2,000 Additional operating labor, hr/ yr 4,160 8,320 18,720 Preliminary SO2 Controls Cost Estimates 11 TABLE 5 CAPITAL COSTS  IN DUCT DRY SORBENT INJECTION Cost Item High Sulfur Coal Lower Sulfur Coal Boiler   100 MMBtu/ hr Boiler   250 MMBtu/ hr Boiler   1000 MMBtu/ hr Boiler   100 MMBtu/ hr Boiler   250 MMBtu/ hr Boiler   1000 MMBtu/ hr DIRECT COSTS ($): Pebble lime system 468,787 839,447 2,215,315 324,845 575,451 1,518,624 Hydrate lime handling system 54,480 97,545 257,422 37,751 66,868 176,466 Ash system modifictions 187,608 356,296 940,270 128,607 244,245 644,566 Miscellaneous equipment 291,655 522,209 1,378,118 202,102 357,981 944,717 Civil, electrical, and other miscellaneous equipment ( 40%) 451,138 726,199 1,916,450 277,322 497,818 1,313,749 TOTAL DIRECT PROCESS CAPITAL ($) 1,453,668 2,541,696 6,707,575 970,626 1,742,363 4,598,122 INDIRECT COSTS: GENERAL FACILITIES 72,683 127,085 335,379 48,531 87,118 229,906 ENGINEERING AND HOME OFFICE FEES 145,367 254,170 670,758 97,063 174,236 459,812 PROCESS CONTINGENCY 72,683 127,085 335,379 48,531 87,118 229,906 PROJECT CONTINGENCY 261,660 457,505 1,207,364 174,713 313,625 827,662 TOTAL PLANT COST ( TPC) ($): 2,006,062 3,507,541 9,256,454 1,339,465 2,404,461 6,345,409 CONSTRUCTION YEARS < 1 < 1 < 1 < 1 < 1 < 1 ALLOAWANCE FOR FUNDS DURING CONSTRUCTION 0 0 0 0 0 0 TOTAL PLANT INVESTMENT ( TPI) ($) 2,006,062 3,507,541 9,256,454 1,339,465 2,404,461 6,345,409 TOTAL PLANT INVESTMENT WITH RETROFIT FACTOR, $ 2,607,881 4,559,803 12,033,390 1,741,304 3,125,799 8,249,031 ROYALTY ALLOWANCE 0 0 0 0 0 0 PREPRODUCTION COST 52,158 91,196 240,668 34,826 62,516 164,981 INVENTORY CAPITAL 23,418 58,554 234,180 23,418 58,554 234,180 INITIAL CATALYST AND CHEMICALS 0 0 0 0 0 0 TOTAL PLANT REQUIREMENTS ($) 2,683,457 4,709,553 12,508,238 1,799,548 3,246,869 8,648,192 TOTAL PLANT REQUIREMENTS ($/ MMBtu): 26,835 18,838 12,508 17,995 12,987 8,648 Preliminary SO2 Controls Cost Estimates 12 TABLE 6 CAPITAL COSTS  SPRAY DRYER ABSORBER Cost Item Coal Boiler   100 MMBtu/ hr Boiler   250 MMBtu/ hr Boiler   1000 MMBtu/ hr DIRECT COSTS ($): SDA Vessels/ Reagent/ Accessories 1,145,452 1,666,112 2,603,300 Flue gas handling ( including ID fans) 647,356 1,010,172 2,312,618 Chimney 515,451 978,916 2,633,019 Waste handling 358,320 680,501 1,845,819 Miscellaneous support equipmentm, $ 316,733 601,522 1,637,391 TOTAL DIRECT PROCESS CAPITAL ($) 2,983,312 4,937,223 11,032,147 INDIRECT COSTS: GENERAL FACILITIES 149,166 246,861 551,607 ENGINEERING AND HOME OFFICE FEES 298,331 493,722 1,103,215 PROCESS CONTINGENCY 149,166 246,861 551,607 PROJECT CONTINGENCY 536,996 888,700 1,985,786 TOTAL PLANT COST ( TPC) ($): 4,116,971 6,813,368 15,224,363 CONSTRUCTION YEARS < 1 < 1 < 1 ALLOAWANCE FOR FUNDS DURING CONSTRUCTION 0 0 0 TOTAL PLANT INVESTMENT ( TPI) ($) 4,116,971 6,813,368 15,224,363 TOTAL PLANT INVESTMENT WITH RETROFIT FACTOR, $ 5,352,062 8,857,378 19,791,671 ROYALTY ALLOWANCE 0 0 0 PREPRODUCTION COST 107,041 177,148 395,833 INVENTORY CAPITAL 8,748 21,870 87,480 INITIAL CATALYST AND CHEMICALS 0 0 0 TOTAL PLANT REQUIREMENTS ($) 5,467,851 9,056,396 20,274,985 TOTAL PLANT REQUIREMENTS ($/ MMBtu) 54,679 36,226 20,275 Preliminary SO2 Controls Cost Estimates 13 TABLE 7 CAPITAL COSTS  WET FLUE GAS DESULFURIZATION Cost Item High Sulfur Coal Lower Sulfur Coal Boiler   100 MMBtu/ hr Boiler   250 MMBtu/ hr Boiler   1000 MMBtu/ hr Boiler   100 MMBtu/ hr Boiler   250 MMBtu/ hr Boiler   1000 MMBtu/ hr DIRECT COSTS ($): Scrubber and miscellaneous equipment 1,350,509 2,564,812 6,768,580 1,350,510 2,564,812 6,768,580 Reagent feed and prep system 943,100 1,791,082 4,677,047 728,540 1,383,601 3,601,701 Flue gas handling ( including ID fans) 405,153 769,444 2,030,574 405,153 769,444 2,030,574 Waste handling 148,556 282,129 744,544 120,189 228,256 602,372 Chimney 515,451 978,916 2,633,019 515,451 978,916 2,633,019 Electrical, piping, valves, and other accessories 135,051 256,481 676,858 135,051 256,481 676,858 TOTAL DIRECT PROCESS CAPITAL ($) 3,497,819 6,642,864 17,530,623 3,254,893 6,181,510 16,313,105 INDIRECT COSTS: GENERAL FACILITIES 174,891 332,143 876,531 162,745 309,076 815,655 ENGINEERING AND HOME OFFICE FEES 349,782 664,286 1,753,062 325,489 618,151 1,631,311 PROCESS CONTINGENCY 174,891 332,143 876,531 162,745 309,076 815,655 PROJECT CONTINGENCY 629,607 1,195,716 3,155,512 585,881 1,112,672 2,936,359 TOTAL PLANT COST ( TPC) ($): 4,826,991 9,167,152 24,192,260 4,491,753 8,530,484 22,512,085 CONSTRUCTION YEARS < 1 < 1 < 1 < 1 < 1 < 1 ALLOAWANCE FOR FUNDS DURING CONSTRUCTION 0 0 0 0 0 0 TOTAL PLANT INVESTMENT ( TPI) ($) 4,826,991 9,167,152 24,192,260 4,491,753 8,530,484 22,512,085 TOTAL PLANT INVESTMENT WITH RETROFIT FACTOR, $ 6,275,088 11,917,298 31,449,938 5,839,279 11,089,629 29,265,711 ROYALTY ALLOWANCE 0 0 0 0 0 0 PREPRODUCTION COST 125,502 238,346 628,999 116,786 221,793 585,314 INVENTORY CAPITAL 23,418 58,554 234,180 3,720 9,310 37,250 INITIAL CATALYST AND CHEMICALS 0 0 0 0 0 0 TOTAL PLANT REQUIREMENTS ($) 6,424,007 12,214,198 32,313,117 5,959,784 11,320,732 29,888,275 TOTAL PLANT REQUIREMENTS ($/ MMBtu): 64,240 48,857 32,313 59,598 45,283 29,888 Preliminary SO2 Controls Cost Estimates 14 TABLE 8 CAPITAL COSTS  WET FLUE GAS DESULFURIZATION Cost Item Oil Boiler   100 MMBtu/ hr Boiler   250 MMBtu/ hr Boiler   1000 MMBtu/ hr DIRECT COSTS ($): Scrubber and miscellaneous equipment 1,329,344 2,524,615 6,662,499 Reagent feed and prep system 666,534 1,265,844 3,340,582 Flue gas handling ( including ID fans) 398,803 757,384 1,998,750 Waste handling 91,651 174,059 459,344 Chimney 372,216 706,892 1,865,500 Electrical, piping, valves, and other accessories 132,934 252,462 666,250 TOTAL DIRECT PROCESS CAPITAL ($) 2,991,483 5,681,255 14,992,925 INDIRECT COSTS: GENERAL FACILITIES 149,574 284,063 749,646 ENGINEERING AND HOME OFFICE FEES 299,148 568,126 1,499,292 PROCESS CONTINGENCY 149,574 284,063 749,646 PROJECT CONTINGENCY 538,467 1,022,626 2,698,726 TOTAL PLANT COST ( TPC) ($): 4,128,246 7,840,132 20,690,236 CONSTRUCTION YEARS < 1 < 1 < 1 ALLOAWANCE FOR FUNDS DURING CONSTRUCTION 0 0 0 TOTAL PLANT INVESTMENT ( TPI) ($) 4,128,246 7,840,132 20,690,236 TOTAL PLANT INVESTMENT WITH RETROFIT FACTOR, $ 5,366,720 10,192,172 26,897,307 ROYALTY ALLOWANCE 0 0 0 PREPRODUCTION COST 107,334 203,843 537,946 INVENTORY CAPITAL 2,000 5,000 19,500 INITIAL CATALYST AND CHEMICALS 0 0 0 TOTAL PLANT REQUIREMENTS ($) 5,476,054 10,401,016 27,454,753 TOTAL PLANT REQUIREMENTS ($/ MMBtu) 54,761 41,604 27,455 Preliminary SO2 Controls Cost Estimates 15 TABLE 9 SO2 Technologies Levelized Costs Fuel Technology SO2 Reduction Capacity Factor $/ Ton of SO2 % % Boiler 100 MMBtu/ hr Boiler 250 MMBtu/ hr Boiler 1000 MMBtu/ hr Coal IDSI high sulfur coal 40 14 3543 2471 1703 50 1292 992 776 83 943 763 633 Coal IDSI lower sulfur coal 40 14 4283 2952 1986 50 1504 1131 870 83 1075 849 697 Coal SDA 90 14 3,920 2,611 1,500 50 1,209 842 531 83 790 569 381 Coal Wet FGD high sulfur coal 90 14 3,513 2,708 1,789 50 1,046 820 563 83 664 528 373 Coal Wet FGD lower sulfur coal 90 14 4,495 3,460 2,273 50 1,326 1,036 704 83 836 661 461 Oil Wet FGD 90 10 10,160 7,801 5,082 50 2,126 1,654 1,109 86 1,285 1,011 693 Preliminary SO2 Controls Cost Estimates 16 TABLE 10 COST SENSITIVIY EVALUATIONS   SO2 TECHNOLOGIES $/ ton of SO2 Fuel Technology Sensitivity Parameter( 1) SO2 Reduction % Capacity Factor % 100 MMBtu/ hr 250 MMBtu/ hr 1000 MMBtu/ hr Coal IDSI high sulfur coal Increased power cost 40 14 50 83 3572 1320 972 2500 1020 792 1732 805 662 Coal SDA Increased power cost 90 14 50 83 3929 1218 799 2620 852 578 1509 541 391 Coal WFGD high sulfur coal Increased power cost 90 14 50 83 3533 1065 683 2727 839 547 1808 582 392 Coal SDA Increased capital cost 90 14 50 83 4613 1403 906 3070 971 646 1757 603 425 Coal WFGD high sulfur coal Increased capital cost 90 14 50 83 4120 1216 766 3170 949 606 2094 648 425 NOTES 1. Two sensitivity parameters were evaluation: 1) increased power cost from 25 mills/ kwh to 50 mills/ kwh and 2) an increase of 20 percent in the technology capital cost.


[Federal Register Volume 78, Number 209 (Tuesday, October 29, 2013)]
[Notices]
[Pages 64555-64556]
[FR Doc No: 2013-25447]

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SECURITIES AND EXCHANGE COMMISSION

Submission for OMB Review; Comment Request

Upon Written Request Copies Available From: Securities and Exchange
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Extension:
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    Notice is hereby given that, pursuant to the Paperwork Reduction
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    Dated: October 23, 2013.
Kevin M. O'Neill,
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[FR Doc. 2013-25447 Filed 10-28-13; 8:45 am]
BILLING CODE 8011-01-P