[Federal Register Volume 76, Number 57 (Thursday, March 24, 2011)]
[Notices]
[Pages 16650-16652]
[FR Doc No: 2011-6909]

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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-64097; File No. SR-BX-2010-079]
Self-Regulatory Organizations; NASDAQ OMX BX, Inc.; Order Approving
Proposed Rule Change To Amend Chapter IV of the BOX Rules To Allow
Executing Participants To Provide BOX a List of the Order Flow
Providers for Which the Executing Participants Will Provide Directed
Order Services

March 18, 2011.

I. Introduction

    On December 3, 2010, NASDAQ OMX BX, Inc. (the ``Exchange'') filed
with the Securities and Exchange Commission (``Commission''), pursuant
to Section 19(b)(1) of the Securities Exchange Act of 1934 (``Act'')
\1\ and Rule 19b-4 thereunder,\2\ a proposal to amend the rules
governing its Directed Order process to: (i) Allow an Executing
Participant (``EP'') to provide BOX a list of the Order Flow Providers
(``OFPs'') for which the EP will provide Directed Order services and
(ii) provide that BOX would reveal to the EP the participant ID of the
OFP sending the Directed Order.\3\ The proposed rule change was
published for comment in the Federal Register on December 20, 2010.\4\
The Commission received no comments on the proposal. This order
approves the proposal.
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    \1\ 15 U.S.C. 78s(b)(1).
    \2\ 17 CFR 240.19b-4.
    \3\ Shortly after the filing of the proposed rule change, the
Exchange withdrew an earlier proposal relating to the non-anonymity
of Directed Orders (SR-BSE-2005-52). See Securities Exchange Act
Release No. 53357 (February 23, 2006), 71 FR 10730 (March 2, 2006)
(SR-BSE-2005-52).
    \4\ See Securities Exchange Act Release No. 63539 (December 14,
2010), 75 FR 79429 (``Notice'').
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II. Description of the Proposal

    Under the BOX's Directed Order process, Market Makers on BOX are
able to handle orders on an agency basis directed to them by OFPs. An
OFP sends a Directed Order to BOX with a designation of the Market
Maker to whom the order is to be directed. BOX then routes the Directed
Order to the appropriate Market Maker. Under Chapter VI, Section
5(c)(ii) of the BOX Rules, a Market Maker only has two choices when
receiving a Directed Order: (1) Submit the order to the Price
Improvement Period auction process (``PIP''); \5\ or (2) send the order
back to BOX for placement onto the BOX Book.
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    \5\ See Chapter V, Section 18 of the BOX Rules.
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    A Market Maker who desires to accept Directed Orders must
systemically indicate that it is an EP whenever the Market Maker wishes
to receive Directed Orders from the BOX Trading Host. If a Market Maker
does not systemically indicate that it is an EP, then the BOX Trading
Host will not forward any Directed Orders to that Market Maker. In such
a case, the BOX Trading Host will send the order directly to the BOX
Book. If a Market Maker has systemically indicated that it wishes to
receive Directed Orders, it shall not, under any circumstances, reject
the receipt of a Directed Order from the BOX Trading Host nor reject
the Directed Order back to the OFP who sent it.\6\
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    \6\ See Chapter VI, Section 5(c)(i) of the BOX Rules.
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    The Exchange proposes to amend Chapter VI, Section 5(c)(i) of the
BOX Rules to allow EPs to provide BOX a list of OFPs for which the EP
will provide Directed Order services. Under the proposal, prior to
accepting any Directed Order through the Trading Host, an EP must
inform BOX of the OFPs from whom it has agreed to accept Directed
Orders (``Listed OFPs'' or ``LOFPs''). The Trading Host will then only
send to the EP Directed Orders from LOFPs. Further, under the proposal,
the BOX Trading Host would

reveal to the EP the participant ID of the OFP sending the Directed
Order.\7\
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    \7\ Pursuant to an existing pilot program, Directed Orders are
not anonymous. See e.g., Securities Exchange Act Release Nos. 63540
(December 14, 2010), 75 FR 79432 (December 20, 2010) (continuing the
practice of non-anonymous Directed Orders, originally established in
SR-BSE-2006-14, as a pilot program until December 31, 2010
(``Directed Order Pilot Program'')) and 63591 (December 21, 2010),
75 FR 81687 (December 28, 2010) (extending the date of the Directed
Order Pilot Program until June 30, 2011). The proposed rule change
would make permanent this feature of the Directed Order process.
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III. Discussion

    After careful review of the proposal, the Commission finds that the
proposed rule change is consistent with the requirements of the Act and
the rules and regulations thereunder applicable to a national
securities exchange \8\ and, in particular, the requirements of Section
6 of the Act.\9\ Specifically, as discussed below, the Commission finds
that the proposed rule change is consistent with Section 6(b)(5) of the
Act,\10\ which requires, among other things, that the rules of a
national securities exchange be designed to prevent fraudulent and
manipulative acts and practices, to promote just and equitable
principles of trade, to foster cooperation and coordination with
persons engaged in regulating, clearing, settling, and processing
information with respect to, and facilitating transactions in
securities, to remove impediments to and perfect the mechanism of a
free and open market and a national market system, and, in general, to
protect investors and the public interest; and are not designed to
permit unfair discrimination among customers, issuers, brokers, or
dealers.
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    \8\ In approving the proposed rule change, the Commission has
considered the proposed rule's impact on efficiency, competition,
and capital formation. 15 U.S.C. 78c(f).
    \9\ 15 U.S.C. 78f.
    \10\ 15 U.S.C. 78f(b)(5).
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    Section 6(b)(5) of the Act prohibits an exchange from establishing
rules that treat market participants in an unfairly discriminatory
manner. Section 6(b)(5) of the Act does not prohibit exchange members
or other broker-dealers from discriminating, so long as their
activities are otherwise consistent with the Federal securities laws.
Nor does Section 6(b)(5) of the Act require exchanges to preclude
discrimination by broker-dealers. Broker-dealers commonly differentiate
between customers based on the nature and profitability of their
business.
    Currently under BOX's rules, an Options Participant that is not a
Market Maker may provide an opportunity for price improvement to a
customer order by submitting it to the PIP. An Options Participant may
decide who to accept as its customers and further choose to provide
price improvement to some customer orders, but not others, by
exercising discretion as to whether it chooses to send a particular
order to the PIP auction.\11\ An Options Participant would know the
identity of its customer in deciding whether to provide this
opportunity for price improvement. Market Makers may also provide an
opportunity for price improvement to Directed Orders by submitting them
into the PIP. The proposed rule change, by permitting a Market Maker to
designate those OFPs from which it will accept Directed Orders and to
be provided with the identity of the OFP sending a Directed Order,
would allow a Market Maker to decide in advance that it will provide an
opportunity for price improvement only to orders from certain OFPs.\12\
Thus, the proposal will provide information to Market Makers that are
EPs that is the same information available to other BOX members when
they decide whether to provide price improvement to a particular order.
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    \11\ See also Rule 723 of the International Securities Exchange,
LLC (Price Improvement Mechanism) and Rule 6.74A of the Chicago
Board Options Exchange, Incorporated (Automated Improvement
Mechanism).
    \12\ Specialists and other market makers may establish payment
for order flow relationships with firms on a discretionary basis. A
specialist or market maker may pay varying amounts for order flow
received from different firms or different customers within firms.
Unlike payment for order flow, which principally benefits
intermediaries and, indirectly, their customers through possibly
lower fees and better services, customers' orders executed through
the PIP auction directly benefit customers with the opportunity for
an improved price.
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    While customer anonymity may be valuable in ensuring that broker-
dealers comply with legal obligations in a variety of circumstances,
such as market makers' firm quote obligations, customer anonymity is
not required of exchanges, particularly when disclosure of customer
identity could provide benefits to certain customers beyond those
required by the Federal securities laws or exchange rules. In
particular, market makers may be willing to offer better execution
prices to certain customers' orders (e.g., retail customers' orders).
The Commission does not believe that it would be inconsistent with the
Federal securities laws for the Exchange to provide, under the
circumstances set forth in this proposal, the means for its Market
Makers to differentiate between customers in providing price
improvement or other non-required advantages to certain customers. The
Exchange's proposal treats all Market Makers the same and establishes
no requirements for which OFPs a Market Maker designates as LOFPs or
for which orders a Market Maker chooses to provide an opportunity for
price improvement. The Commission does not believe that the absence of
Exchange rules specifying which orders a Market Maker may execute at
prices better that its public quote is unfairly discriminatory.
    The Commission notes that allowing a Market Maker to know the
identity of firms sending Directed Orders may provide further incentive
to that Market Maker to provide price improvement. A Market Maker that
receives a Directed Order would be required to decide whether to send
the order to the PIP and guarantee a price equal to or better than the
NBBO to such order, or to release the order to the BOX book. The Market
Maker's decision about whether to choose to guarantee a particular
order at a price equal to or better than the NBBO may be affected by
this proposal because it provides Market Makers with information to
differentiate between orders from informed traders (i.e., their
competitors) and orders from uninformed traders. It is well known in
academic literature and industry practice that prices tend to move
against market makers after trades with informed traders, often
resulting in losses for market makers.\13\ Thus, there is a strong
economic rationale for market makers not providing informed traders
price improvement. Uninformed investors end up bearing the cost of
these market maker losses through wider spreads that market makers need
to quote to uninformed investors due to informed order flow.\14\
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    \13\ See Stoll, H. R., ``The supply of dealer services in
securities of markets,'' Journal of Finance 33 (1978), at 1133-51;
Glosten, L. and P. Milgrom, ``Bid ask and transaction prices in a
specialist market with heterogeneously informed agents,'' Journal of
Financial Economics 14 (1985), at 71-100; and Copeland, T., and D.
Galai, ``Information effects on the bid-ask spread,'' Journal of
Finance 38 (1983), at 1457-69.
    \14\ Id.
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    Accordingly, while the Exchange's proposal would permit a BOX
Market Maker to discriminate among customers in providing prices better
than its quote, the Commission does not believe that this
discrimination is inconsistent with Section 6(b)(5) of the Act.
    The Commission continues to believe that under the proposal, a
Market Maker would maintain the incentive to quote aggressively to gain
priority with respect to orders entered on the BOX book. Further, the
Commission believes that there is rigorous competition for order flow
across options exchanges, such that any widening of quotes on one
market is an opportunity for another option

market to capture order flow.\15\ In fact, the Options Order Protection
and Locked/Crossed Market Plan provides protection from one exchange
ignoring better quoted prices on another market and will continue to
promote quote competition across options exchanges.\16\
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    \15\ See Robert Battalio, ``Third Market Broker-Dealers: Cost
Competitors or Cream Skimmers?'' Journal of Finance, 1997; and
Robert Battalio, Robert Jason Greene, and Robert Jennings, ``How do
Competing Specialists and Preferencing Dealers Affect Market
Quality?'' Review of Financial Studies, 1997.
    \16\ See Securities Exchange Act Release No. 60405 (July 30,
2009), 74 FR 39362 (August 6, 2009).
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    For the foregoing reasons, the Commission finds that the proposed
rule change is consistent with the Act and the rules and regulations
thereunder applicable to a national securities exchange, and, in
particular with Section 6(b)(5) of the Act.\17\
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    \17\ 15 U.S.C. 78f(b)(5).
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IV. Conclusion

    It is therefore ordered, pursuant to Section 19(b)(2) of the
Act,\18\ that the proposed rule change (File No. SR-BX-2010-079) is
approved.
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    \18\ 15 U.S.C. 78s(b)(2).

    For the Commission, by the Division of Trading and Markets,
pursuant to delegated authority.\19\
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    \19\ 17 CFR 200.30-3(a)(12).
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Cathy H. Ahn,
Deputy Secretary.
[FR Doc. 2011-6909 Filed 3-23-11; 8:45 am]
BILLING CODE 8011-01-P


2 1 CHAPTER 2. METHODOLOGY AND THE BASE CASE The chapter explains how pollution control options for emissions of sulfur dioxide ( SO2), mercury, and carbon dioxide ( carbon) from the electric power industry were analyzed. The chapter also provides a forecast of future electric generation, air emissions, and fossil fuel use for the Base Case for this study.

The study uses a Base Case to measure the changes in electric generation practices, air emissions and costs that would result from control options for SO2, mercury, and carbon emissions. The Base Case assumes current federal and State requirements for air pollution control including the future implementation of Title IV of the Clean Air Act Amendments of 1990 ( CAAA) for SO2 and nitrogen oxide ( NOx) emissions and the NOx SIP call. It is assumed that compliance with the NOx SIP call will be achieved through a regional cap and trade program.

METHODOLOGY This section explains the approach and describes the key assumptions that are used to analyze different pollution control options for the electric power industry. Most of the assumptions made in this study are described in greater detail in U. S. Environmental Protection Agency, Analyzing Electric Power Industry under the CAAA, March 1998.1 However, the Agency updated the mercury emissions and mercury control cost functions during the preparation of this study and the details of these revised assumptions are provided in technical appendices of this report.

Analytical Overview For each pollution control alternative, this analysis examined the changes from the Base Case in estimated air emissions, production costs, generation, capacity, and fuel use.

The analyses have a wide scope geographically and over time, examining the actions of close to 8,000 utility and non utility electric generation units in all 48 contiguous States for a period starting in 2005 and running through 2025. The results are reported for the years 2005, 2007, and 2010. Examining the industry over many years makes it possible to take many important dynamic effects into account. For example, the effects of efficiency gains over time and the choice between capital intensive control measures and measures that increase operating costs can be investigated by projecting the power industry's response over a long analytical period. In addition, the effects of allowing the banking of emission reductions can be analyzed only in a dynamic framework.

1 This report can also be found at an EPA website with the address: http:// www. epa. gov/ capi. 2 2 The Integrated Planning Model ( IPM) was used in this analysis to predict the actions of power plant operators over time in response to alternative levels of air pollution controls. IPM is a detailed computer model of the electric power industry. The model finds the most efficient ( that is, the least cost) way to satisfy the demand for electricity under a series of limitations or constraints. The constraints under which IPM " produces" electricity can include a limit on tons of NOx, SO2, carbon, and mercury emissions during the summer ( ozone season), or annually. By setting constraints on any one, or combination of these air pollutants over time, EPA can model various control options for emissions cap and trade programs. The Base Case for this analysis is provided by running IPM with an ozone ( summer) season limitation of 544 thousand tons of NOx emissions in 22 eastern States and the District of Columbia covered by the NOx SIP call. 2 This case also has a national SO2 emissions cap for the Title IV SO2 allowance trading program. 3 To look at other control options that apply cap and trade approaches, EPA simply adds other air emissions constraints, and/ or changes the NOx and SO2 constraints.

IPM can also be used to examine rate based controls ( e. g. an emissions limitation of .15 pounds of NOx for every million BTUs of fossil energy use). This allows consideration of control options that require removal of a specified percentage of a pollutant from a generation unit's emissions ( e. g. removal of 80 percent of the mercury emissions from a coal fired boiler flue gases). EPA has generally used these types of " command and control" options for Section 112 controls under the CAAA in setting standards for hazardous air pollutants based on the maximum achievable control technology ( MACT). If EPA decides to regulate mercury emissions from coal fired electric generation units under the CAAA, the Agency could set MACT requirements for these units. To analyze this type of control, plants in the model are given specific emission rates that match the control requirements and added pollution control costs that cover the capital, operating, and maintenance expenses. In a single model run, IPM is able to consider cap andtrade controls on some pollutants and the setting of emission rates under MACT requirements for others.

IPM Use and Assumptions IPM has been used for over ten years by electric utilities, trade associations, and government agencies both in the U. S. and abroad to address a wide range of issues regarding electric power markets. It has been used for capacity planning, environmental policy and compliance planning, wholesale price forecasting, and asset valuation. 4 EPA has used this model extensively for environmental policy and regulatory analysis. For example, EPA has used IPM to analyze the emissions reductions and costs for the electric power industry of:

  NOx, SO2, and mercury emissions control strategies as part of the Clean Air Power Initiative ( CAPI) in 1996,

2 The ozone season is from May 1st to September 30th in the NOx SIP call. This is also referred to as the " summer season" in this study. 3 EPA also looks at other CAAA controls and state environmental requirements in the base case, which will be explained later in the chapter. 4 ICF Resources developed the Integrated Planning Model as a commercial capacity planning tool and for policy applications over wide geographic areas or for the entire country. EPA had ICF set up IPM for environmental policy analysis of options to control emissions form NOx. SO2, carbon, and mercury with the assumptions described in this chapter. Under EPA's direction, ICF prepared the Base Case and control options presented in this study. 2 3   Implementation of the Clean Air Act Amendments of 1990 as required under Section 812 of CAAA,

  Implementation of National Ambient Air Quality Standards ( NAAQS) for ozone and particulates in the Regulatory Impact Analysis supporting these rules,

  Alternative NOx emissions trading and rate based programs and during the Ozone Transport Assessment Group ( OTAG) process in 1996 and 1997,

  The CAAA Title IV NOx Rule,

  NOx control options for the NOx SIP call in 1997 and 1998 in the Regulatory Impact Analysis to support this rulemaking.

IPM has undergone extensive review and validation over this ten year period. In April 1996, EPA requested participants in the CAPI process to comment on the Agency's approach to forecasting electric power generation and selected air emissions. EPA received many helpful comments and made a series of changes in its methodology and assumptions based on commenters= recommendations. IPM and EPA's modeling assumptions were reviewed as part of the OTAG process and in the preparation of the NOx SIP call. Again, changes were made to the methodology and assumptions based on commenters= recommendations.

The version of IPM currently used by EPA represents the U. S. electric power market in 21 regions, as depicted in Exhibit 2 1. These regions correspond in most cases to the regions and sub regions used by the North American Electric Reliability Council ( NERC). IPM models the electricity demand, generation, transmission, and distribution within each region as well as movement of power on the transmission grid that connects the different electric generation regions. EPA uses assumptions in IPM that are meant to reflect wholesale competition occurring throughout the electric power industry.

The model includes existing utility power plants as well as independent power producers and cogeneration facilities that sell firm capacity into the wholesale market. Data on the existing boiler and generator population, which consists of close to 8,000 records, are maintained in EPA's National Electric Energy Data System ( NEEDS). In order to make the modeling more time and cost efficient, the individual boiler and generator data are aggregated into A model@ plants. EPA's application of the model has focused heavily on understanding the future operations of coal fired units, which will have the greatest air emissions among the fossil fired 2 4 Exhibit 2 1 Integrated Planning Model Regions in the Configuration Used by EPA CNV SPPN ERCT NENG LILC UPNY FRCC WUMS MECS MACS MACE MACW SOU SPPS WSCP WSCR MAPP TVA ECAO MANO VACA 2 5 units. The operation of other types of non fossil fuel fired generation capacity, including nuclear and renewables, are also simulated but at a higher degree of aggregation.

Working with these existing model plants and representations of alternative new power plant options, IPM determines the least cost means for supplying electricity demand while limiting air emissions to remain below specified policy limits. While determining the least cost solution, IPM also determines the optimal compliance strategy for each model plant as part of system wide effort to minimize electric generation costs. For this study, IPM was set up to allow selection of a wide range of compliance options by the model plants in each simulation, including:

  Fuel Switching   For example, switching from high sulfur coal to low sulfur coal.

  Repowering   For example, repowering an existing coal plant to a natural gas combined cycle plant.

  Pollution Control Retrofit   For example, installing selective catalytic reduction ( SCR), selective non catalytic reduction ( SNCR), or gas reburn ( to reduce NOx emissions), or flue gas desulfurization ( to control SO2 emissions).

  Economic Retirement   For example, retiring an oil or gas steam plant.

  Dispatch Adjustments   For example, running high NOx cyclone units less often, and low NOx combined cycle plants more often.

IPM provides estimates of air emissions changes, incremental electric power generation costs, changes in fuel use and electric generation practices, and other potential impacts for each air pollution policy analyzed. In using IPM to analyze air emission policies over the past three years, EPA has developed a set of data and assumptions that reflect the best available information on the electricity market and operating factors. These data and assumptions can be grouped into the following four categories:

  Macro Energy and Economic Assumptions   These assumptions are related primarily to electricity demand projections, fuel prices, power plant availability, heat rates, lifetimes, and capacity factors. Also included in this category are discount rate and year dollar assumptions.

  Electric Technology Cost and Performance   These assumptions are related to electric technology cost and performance for existing and new plants, as well as for existing plant refurbishment and repowering.

  Air Emissions Rates under the Base Case   These assumptions cover current EPA and State requirements that will affect emission levels from various facilities. The focus has been on SO2 and NOx controls where EPA and the States have promulgated regulations. EPA also determines carbon and mercury emissions through the fuels used for electric generation. 2 6   Pollution Control Performance and Costs   These assumptions cover the performance and unit costs of pollution control technologies for NOx, SO2 and mercury. There are no economically available direct pollution control technologies for carbon emissions for electric generation units. Reductions of carbon emissions from the power industry result from reductions in electric demand, greater generation unit efficiency, fuel switching, and changes in the mix of generation technologies.

Macro Energy and Economic Assumptions In developing the analysis for this study, EPA makes assumptions about major macro energy and economic factors, as shown in Exhibit 2 2. See Appendix No. 2 of EPA= s March 1998 report Analyzing Electric Power Generation under the CAAA for details on most of the macro energy and economic factors.

Exhibit 2 2 Key Baseline Assumptions for Electricity Generation Factor Assumption Discount Rate ( percent per year) 6 Conversion Factor from 1997 to 1990 Dollars 0.83 Electricity Demand Growth Rate ( percent per year) a 1997 2000 = 1.6 2001 2010 = 1.8 > 2010 = 1.3 Reductions due to Climate Change Action Plan ( Billion kWh) 2005 = 228 2007 = 293 2010 = 389 > 2019 = 608 Power Plant Lifetimes Fossil Steam = 65 years if

50 MW = 45 years if < 50 MW Nuclear = 40 year license length Turbines = 30 years U. S. Nuclear Capacity ( gigawatts) 2005 = 87 2007 = 86 2010 = 81 2020 = 50 Nuclear Capacity Factors ( percent) 2005 = 80 2007 = 82 2010 = 81 2020 = 83 2 7 Exhibit 2 2 ( continued) Key Baseline Assumptions for Electricity Generation Factor Assumption World Oil Prices ( 1997$ per BBL) 2005 = 20.50 2007 = 20.80 2010 = 21.20 2020 = 22.40 Wellhead Natural Gas Price ( 1997$ per mmBtu) b 2005 = 2.00 2007 = 2.00 2010 = 2.00 Coal Steam Power Plant Availability ( percent) 2005/ 10/ 20 = 85 Existing Power Plant Heat Rates No change over time Coal Mining Productivity Increases ( percent change per year) 1995 1999 = 3.1 2000 2004 = 2.8 2005 2009 = 2.4 2010 2014 = 2.1 2015 2025 = 2.1 Average Delivered Coal Pricesb ( percent change per year 2001 2010)  2.0 a Does not include any adjustment for potential improvements related to the Climate Change Action Plan. b Based on recent ICF analyses using updated coal mining productivity and supply for coal, and technology and supply assumptions for gas. Note that the natural gas prices are not an assumption in the model, but are a forecast of the model.

Electric Energy Cost and Operating Assumptions In order to simulate the electric power market under Base Case conditions and for each of the air emission control options, assumptions are made on the cost and performance of new power plants as well as for repowering existing power plants. These characterizations of new power plant costs and performance are used in IPM to determine the least cost means for meeting projected future electricity requirements subject to alternative pollution control restrictions.

Initially, EPA looked at all the existing and emerging electric generation technologies that could be used in the future and determined which are likely to be economic to build from 2000 to 2025. Those technologies that looked viable were then included in IPM. Power plant cost and performance assumptions that are included in IPM for new conventional and unconventional generation units include:

  New Conventional Generation Units  Conventional Pulverized Coal;  Advanced Coal ( Integrated Gasification Combined Cycle  IGCC); 2 8  Combined Cycle;  Combustion Turbine; and  Nuclear   New Renewable/ Nontraditional Generation Units  Biomass IGCC;  Solar Photovoltaics;  Solar Thermal;  Geothermal; and  Wind Cost and performance projections were developed for the period 2005 through 2010 in order to capture changes in technology over time. Regional variations in the capital construction and labor costs in making assumptions about the expenses of bringing new capacity on line were also developed. EPA relied heavily on work that the Energy Information Administration ( EIA) did in support of recent Annual Energy Outlooks ( AEO97 and AEO98). EIA had its approach peer reviewed during its development. The Agency also used other well recognized reference sources, such as the Electric Power Research Institute's Technical Assessment Guide.

In addition to these assumptions on new power plants, EPA also developed assumptions on the cost and performance of repowering existing power plants. The following three types of repowering options are considered:

  Repowering Coal Steam to Integrated Gasification Combined Cycle;

  Repowering Coal Steam to Natural Gas Combined Cycle; and   Repowering Oil/ Gas Steam to Natural Gas Combined cycle.

For more details on the assumptions made about the cost and performance of new power plants and repowering of existing power plants, see Appendix No. 3 of EPA= s March 1998 report Analyzing Electric Power Generation under the CAAA. 2 9 Air Emissions under the Base Case EPA had to make assumptions for the Base Case emissions of NOx, SO2, carbon, and mercury for this study. For each pollutant, EPA used a somewhat different approach that is summarized below. Details on assumptions that EPA used in preparing air emissions estimates with IPM can be reviewed in Appendix No. 4 of EPA's March 1998 report, Analyzing Electric Power Generation under the CAAA and EPA's Regulatory Impact Analysis for the NOx SIP Call, FIP, and Section 126 Petitions, Volume 1: Costs and Economic Impacts, September 1998.

NOx Emissions  There are four sets of regulations affecting NOx emissions that are taken into account in this analysis. First, State requirements are considered, especially in California. Second, EPA factors in regulations under Title I of the Clean Air Act, including RACT requirements for existing sources, EPA's New Source Performance Standards, and controls based on Best Available Control Technology ( BACT) and Lowest Achievable Emissions Rates ( LAER) that would be in effect for new sources. Third, the analysis also accounts for the NOx reductions from utility units under Phases I and II of Title IV's Acid Rain Program, which set rate limitations for most coal fired generators greater than 25 MW of capacity. Finally, the NOx SIP call covering eastern States is considered. EPA estimated the NOx rates of generation units that use fossil fuels and renewable fuels, such as municipal waste combustors. EPA takes all of these requirements into account in its determination of individual emissions rates for model plants in its analysis.

SO2 Emissions  EPA focused primarily on the emissions from coal fired units, because they are the dominant source of SO2 emissions in this sector. For existing coal fired generation units that have installed flue gas desulfurization units ( scrubbers), EPA considered how they would operate in the future to maximize SO2 reductions at the lowest fuel costs. For all other existing coal fired generation units, EPA considered limitations that have been placed on them under existing state air pollution control programs and allowed these units to select the cheapest way to comply with the requirements of the Title IV Allowance Trading Program given variations in the sulfur content of coals and their delivered prices. IPM contains sulfur content factors for the different coal grades produced throughout the country that can be combined with energy use estimates for model plants to estimate SO2 emissions. New coal fired units are assumed to have scrubbers and to select coals that allow them to minimize their total operating costs.

Carbon Emissions   EPA considered the use of different types of fossil fuels by model plants in IPM and the relationship between specific fuel grades ( e. g. lignite and bituminous coal) and carbon emissions. The Agency used fuel grade specific carbon dioxide emission factors developed by the Energy Information Administration for this purpose.

Mercury Emissions   For this study, EPA updated the assumptions in the March 1998 report, Analyzing Electric Power Generation under the CAAA for mercury emissions. The most critical sets of assumptions that EPA made in its forecast of mercury emissions are the mercury content of fossil fuels, the mercury reductions that are attributable to different types of boilers at electric generation units, and their existing pollution control equipment and their configuration. 2 10 These assumptions are explained in Appendix A ( mercury concentrations in coal) and Appendix B ( emissions modification factors for electric generation units).

Pollution Control Performance and Cost Assumptions For this study, pollution control performance and cost assumptions were developed for alternative levels of NOx, SO2, carbon, and mercury emissions from power plants. Until this study, IPM was set up to allow model plants in pollution control simulations the opportunity to retrofit only once over the period of the analysis. To allow for the evaluation in this study of the potential actions the power industry may take to implement alternative pollution control requirements that fall at different times over the period examined, IPM was set to allow model plants to undertake two retrofits during a model run.

It is important to recognize that the power industry can do more than just add retrofit controls to lower their air emissions. It can also switch fuels at units, replace older units with new ones, change dispatch practices, or purchase power from nearby regions. For this study, IPM was set up to allow the full range of available options for compliance with alternative pollution control levels.

NOx Controls   Cost analysis suggests that certain types of generation units are more likely to add pollution controls to lower NOx emissions. Existing combustion turbines and combined cycle operations will be unlikely to add NOx controls due to their relatively low levels of emissions and limited use. It is assumed in this study that new combined cycle units are built with selective catalytic reduction ( SCR) on them, which States generally require for compliance with BACT. New combustion turbines are assumed to have low emission rates due to boiler designs that do not necessitate further controls. Additional controls for generation units that use renewable resources were not assumed to be needed.

For this report, its assumed that States will require new coal fired units to have SCR to comply with BACT requirements. New oil/ gas steam units are considered to be uneconomic for the foreseeable future. For existing coal fired and oil/ gas steam units, the costs and performance of various types of NOx controls were examined and where available data suggested that these controls could be employed cost effectively, they were used in IPM. This led to consideration of the following options in the model:

  Coal Fired Steam Electric Generating Units  Combustion Controls;  Selective Catalytic Reduction ( SCR);  Selective Non Catalytic Reduction ( SNCR); and  Natural Gas Reburn.

  Oil and Gas Fired Steam Generating Units  Selective Catalytic Reduction; and  Selective Non Catalytic Reduction. 2 11 The Agency is now aware that vendors are beginning to offer hybrid control options ( combining SCR with SNCR, or SNCR with natural gas reburn). This could ultimately lead to a somewhat different set of actions by the regulated community over time. It is likely to lower the compliance costs the regulated community faces over time for the NOx SIP call.

SO2 Controls   In this analysis, all coal fired units were allowed to lower sulfur dioxide emissions either through the installation of flue gas desulfurization technology ( scrubbers), or the selection of coals with lower sulfur contents. The Agency looked at the recent trend in scrubber installation costs in developing its cost functions.

Carbon Controls  There are no economical post combustion controls available for removing carbon dioxide emissions at this time. Reductions in carbon emissions are possible through changes in dispatch to reduce the use of higher emitting coal fired unit generation, or through replacement of older, less efficient units ( e. g. oil/ gas steam) with newer more efficient ones, such as combined cycle natural gas. Lowering the carbon emissions rates of electric generation units using fossil fuels occurs in IPM through the repowering of units. Coal fired units can repower to combined cycle natural gas ( with a lower carbon emissions rate), or to integrated gasification combined cycle ( improving their efficiency in the use of coal by gasifying it and running it through a combined cycle system). Gas fired steam electric units can also repower to combined cycle natural gas to improve their efficiency. EPA does not consider heat rate improvements by units over time as a compliance strategy in the options that it analyzed. The Agency does assume that because of deregulation of the power industry that heat rates will be maintained and not degrade over time as they have in the past at generation units that use fossil fuels.

Mercury Controls  EPA considered what type of pollution control could be used to lower mercury emissions from coal fired electric generation units in the future. Although EPA, the Department of Energy ( DOE), and the Electric Power Research Institute ( EPRI) have sponsored research in this area in the past, much more needs to be done to develop practical mercury control technologies. Based on current information, EPA's Office of Research and Development ( ORD) concluded that the most likely control technologies to be used in the future, if the Agency makes a determination that it should regulate mercury from coal fired units are those based on activated carbon injection. EPA has seen successful application of these technologies on municipal waste combustors and believes that this experience is transferable to coal fired units. A major research program, however, is underway to field test these technologies and to develop refined estimates of the costs and performance of activated carbon injection technologies. Some researchers are also devoting efforts to considering whether there are more cost effective sorbent materials than activated carbon.

EPA's ORD examined recent work prepared for EPA's Mercury Report to Congress, and work by EPRI, DOE, and other sources and developed the mercury control cost functions used in this report for carbon injection technology. These mercury control costs and performance estimates are provided in Appendix C. The Agency's research office developed these cost and performance functions to allow the Agency to analyze the costs of a mercury control program options. In considering the results of this report, it should be recognized that much more work is 2 12 required in field testing activated carbon injection based technologies in coal fired units and that other technologies may emerge that are effective controlling mercury emissions.

The Agency recognizes that coal cleaning holds some promise for lowering mercury levels in the future from coal fired units. Although EPA was able to account for existing practices of cleaning coal in estimating future mercury emissions in the Base Case, it was not able to analyze its application in any of the alternative pollution control programs considered in this report.

Combination Controls  EPA also developed cost and performance estimates for combining different types of controls such as SCR or SNCR with coal plant scrubbers. With these options, IPM can determine if in some instances, it is optimal to place a scrubber and SCR or SNCR on a unit to reduce SO2 emissions and NOx emissions from a given plant simultaneously. In determining the least cost means for complying with a pollution control option, the model can choose from among these pollution control technologies and change the dispatch of model plants. For example, the model in some cases can reduce the utilization of high NOx emitting units and increase the utilization of low NOx emitting units.

Allowance Allocations and Trading Most of the pollution control options examined in this study are implemented through emissions cap and trade programs. Such trading programs work by allocating allowances which permit the emission of limited quantities of pollution during the specified periods ( e. g. ozone season, or annually), permitting sources to choose how they will comply with control requirements by reducing emissions, or purchasing allowances from other sources. For the analysis provided in this study, the initial distribution of the allowances is not important; the only relevant fact regarding the allowances is their total amount, which determines the total number of tons of air emissions reductions required.

IPM finds the least cost method for producing electric power for the industry as a whole. The model places pollution controls or makes dispatch changes to electric generating units that lead to the achievement of emission reductions at the lowest cost. As a result, some firms' power plants are projected to be tightly controlled, at significant cost, while other firms' plants have no controls beyond those assumed in the baseline.

Realistically, this pattern would not be seen unless a system existed to give incentives to the firms with the most cost effective control possibilities to bear the greatest part of the control burden. EPA's analysis envisions that these incentives are provided by an emissions trading system that provides sources with the opportunity to buy and sell allowances. Under such a system, firms are assumed to either buy or sell allowances depending on their own costs of control in comparison to the market price of allowances. As the price reacts to changes in demands and supplies of allowances, the market will help ensure that the costs of incremental reductions of pollutants covered in trading programs are the same for all participants. 2 13 General Limitations of the Analysis This analysis incorporates a fine grained representation of the behavior of a large number of industrial entities. It covers both a long period of time and a wide geographical area. As with any attempt to project the future in detail, it is subject to limitations and uncertainties. Several factors could lead to cost and emissions impacts above or below the reported impacts. Those factors include the following:

  Speed of Deregulation   This report assumes that electric utility deregulation will continue to move ahead at a steady pace. It also assumes that deregulation will affect the electricity market in specific ways including lower cost of transmission, higher coal plant availability, and lower reserve margins. Should deregulation occur more quickly or more slowly than assumed, or affect the electricity system in different ways, the estimated costs and emissions impacts for these regulatory options may differ.

  Emissions Reduction Costs and Performance   This report uses forecasted changes in electric generation technology, improvements in SO2 controls, and movements in fuel prices over time. These factors are major determinants of the compliance costs of the control options examined in this report. The soundness of the forecasts heavily influences the results of this analysis. The compliance costs of mercury control options rely heavily on the Agency's assumptions about mercury emissions and the cost functions for controlling mercury with activated carbon injection technologies. For each of these areas, there is considerable uncertainty and the results of the mercury control options analysis should be considered preliminary.

  Administrative Costs   No administrative costs are included in this analysis. Electric utilities, State and local air quality regulatory agencies, and EPA will incur administrative costs in addition to the direct costs of complying with the control options analyzed in this study. For some electric generation units, these costs will include monitoring emissions, certifying compliance, modifying permits, and trading allowances. For States and local governments and EPA, there will be program development and implementation costs. Experience under the Title IV SO2 Allowance Trading program suggests that the cap andtrade programs considered in this study will not have large administrative costs. The administrative costs of Title I MACT requirements for other industries are not large.

  Regulatory Program Implementation  The alternative pollution control levels analyzed in this report are assumed to be implemented smoothly and at specific points in time.

  Data Limitations  EPA has constructed a database for this analysis that consists of information on virtually every boiler and generator in the U. S. The Agency has assembled the best information on each boiler and generator that is publicly available. Inevitably, when working with information on such a large number of facilities, some units may not be represented correctly. Especially for the consideration of mercury emissions, EPA had to make many default assumptions regarding the configuration of existing pollution controls, which heavily influences the emissions. Efforts are underway 2 14 to improve the data available on mercury emissions from utility boilers. Comments are welcome from readers with knowledge concerning specific units. Improvements to the database could lead to changes in estimates of emissions and potential cost impacts for the regulatory options analyzed.

BASE CASE As mentioned above, EPA considered implementation of the NOx SIP call and future CAAA Title IV requirements in setting up the Base Case for this study. The NOx SIP call covers the States shown in Exhibit 2 3. For all other States, EPA has assumed implementation of the NSPS, BACT/ LAER, and RACT under Title I of the CAAA, Title IV controls on coal fired units and known future State NOx controls. In regards to the NOx SIP call, the Agency has assumed that the States will participate in the cap and trade program that EPA recommended in the rule and analyzed in its Regulatory Impact Analysis to support the rule.

Electric Generation The Base Case forecast presented in this study covers years 2005 to 2010. Exhibit 2 4 shows the electric generation capacity that EPA forecasts will operate during this time period. The forecast shows a small decline in coal fired generation capacity over time. Gas fired generation capacity increases to meet future electric demand growth. Nuclear generation capacity declines, as some units become noneconomic to operate. Other capacity, which is primarily hydroelectric and other electric generation units using renewable resources, does not change much in the time period analyzed. 2 15 Exhibit 2 3 States Included in EPA's NOx SIP Call WI IL IN MI PA NJ DE CT DC NY MO OH WV KY VA MD NC SC TN GA AL MA RI NH Ozone Transport Region States in the NOx SIP Call Other States in the NOx SIP Call 2 16 Exhibit 2 4 Future Electric Generation Capacity Under the Base Case ( GW)

Fuel Type 2005 2007 2010 Coal 305 305 304 Oil/ Natural Gas 240 250 282 Nuclear 87 86 81 Other* 138 138 138 Total 770 779 805 * Includes hydroelectric, municipal waste combustors, and other renewables, pump storage, and import capability from Mexico and Canada.

Exhibit 2 5 shows the electric generation forecast that EPA is using for this period. Coalfired generation will provide most of the country's power from 2005 and 2010. The greatest growth in electric generation occurs for units that use oil or natural gas. The exhibit shows a decline in the amount and share of power produced by nuclear units by 2010.

Exhibit 2 5 Future Electric Generation under the Base Case ( Billion kWh)

Fuel Type 2005 2007 2010 Coal 2,084 2,091 2,114 Oil/ Natural Gas 561 626 759 Nuclear 609 613 580 Other* 380 383 377 Total 3,634 3,713 3,831 * Includes hydroelectric, municipal waste combustors, and other renewables, pump storage, and import capability from Mexico and Canada.

Greater details on EPA's generation capacity and electric generation forecast can be found in Appendix D. The appendix shows the amount of coal fired and oil gas steam capacity that is retrofitted with post combustion controls due to the NOx SIP call and the changes over time in the repowering of oil/ gas steam units to combined cycle natural gas units. 2 17 Air Emissions Exhibit 2 6 provides a national forecast of the Base Case for NOx, SO2, mercury, and carbon emissions. 5 The chart shows NOx and SO2 emissions dropping over time as a result of CAAA programs that go into effect after 2000 and the greater use of natural gas that is expected by 2010. Unregulated mercury emissions drop a small amount over time due to some shifting towards western coals that are assumed to have generally lower mercury concentrations ( see Exhibit 2 11 below). Unregulated carbon emissions rise as a greater amount of electric generation over time is produced by fossil fuels and nuclear use declines.

The Exhibits 2 7, 2 8, and 2 9 show the regional breakout of these air emissions and electric generation ( Exhibit 2 1 shows the location of each NERC region in the exhibits). The air emissions are regionally highest in the areas that rely most heavily on coal fired generation.

Exhibit 2 6 Future Air Emissions under the Base Case For the Electric Power Industry for Selected Air Pollutants Pollutant Units 2005 2007 2010 Summer Nitrogen Oxides ( NOx) Thousand short tons 1,436 1,449 1,386 Annual Nitrogen Oxides ( NOx) Thousand short tons 4,221 4,255 4,147 Annual Sulfur Dioxides ( SO2) Thousand short tons 11,049 10,864 9,658 Annual Mercury Short tons 51.9 52.0 50.9 Annual Carbon Million Metric tons 605 615 621 Exhibit 2 10 considers in greater depth the sources of mercury emissions. 6 The vast majority of mercury emissions come from coal fired generation. The next largest category of mercury emissions is generation units that use renewable energy sources. Sources of mercury emissions in this category include municipal waste combustors ( MWCs), geothermal units, and units that use coal biproducts. As mentioned earlier, this forecast already considers the effects of required controls on MWCs.

5 EPA is reporting carbon emissions rather than carbon dioxide emissions. To make the conversion to CO2 emissions, the carbon results needed to be multiplied by 3.67. 6 EPA considered whether implementation of the NOx SIP call lead to changes in mercury emissions from the electric power industry from its initial base case prior to promulgation of this rule. The Agency found that the NOx SIP call did not produce changes in mercury emissions in any significant way. The rule is likely to produce a relatively modest shift towards greater natural gas generation. The Agency also has not found technical data or reports that the Agency believes show that NOx controls in themselves remove mercury from boiler flue gases. 2 18 Exhibit 2 7 Regional Electric Generation and Air Emissions for 2005 For the Base Case Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 37 85 27 92 276 1.1 16 ECAO 222 531 165 809 3,029 8.4 118 ERCT 126 261 154 323 565 4.7 45 MACE 46 100 17 57 138 1.4 9 MACW 43 102 28 122 553 2.9 17 MACS 22 53 14 63 211 1.0 8 WUMS 24 57 19 65 195 1.0 12 MANO 85 195 52 225 910 4.4 37 MAPP 74 165 154 354 613 3.8 38 UPNY 58 132 22 63 196 1.2 11 LILC 3 6 2 3 0 0.3 1 NENG 44 104 22 61 191 1.5 12 FRCC 89 180 121 243 319 2.1 28 VACA 127 293 70 271 947 3.6 42 TVA 65 151 45 194 596 2.2 26 SOU 104 235 88 277 1,174 3.9 42 SPPN 39 88 55 155 178 1.4 20 SPPS 113 226 151 305 484 2.7 41 CNV 109 249 32 76 50 1.2 22 WSCP 71 168 19 45 124 0.4 7 WSCR 109 252 178 418 301 2.7 51 TOTAL 1,610 3,634 1,436 4,221 11,049 51.9 605 2 19 Exhibit 2 8 Regional Electric Generation and Air Emissions for 2007 For the Base Case Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 38 87 26 91 272 1.1 16 ECAO 223 533 166 811 2,966 8.4 118 ERCT 129 269 158 333 565 4.7 47 MACE 46 97 19 60 144 1.4 10 MACW 43 104 29 125 569 2.9 18 MACS 23 56 14 65 213 1.1 9 WUMS 25 58 18 64 191 1.0 12 MANO 88 205 51 222 861 4.4 37 MAPP 75 166 155 352 594 3.7 39 UPNY 59 135 22 62 188 1.1 11 LILC 3 6 2 3 0 0.3 1 NENG 44 105 22 62 191 1.5 12 FRCC 95 189 122 242 315 2.0 29 VACA 132 306 71 277 968 3.7 44 TVA 66 153 45 197 567 2.3 26 SOU 103 237 87 279 1,125 4.0 42 SPPN 40 90 56 156 179 1.4 20 SPPS 119 232 156 307 484 2.7 42 CNV 113 261 33 80 50 1.2 24 WSCP 71 168 19 45 124 0.4 7 WSCR 110 255 179 420 297 2.7 52 TOTAL 1,645 3,713 1,449 4,255 10,864 52.0 615 2 20 Exhibit 2 9 Regional Electric Generation and Air Emissions for 2010 For the Base Case Billion kWh NOx ( 1,000 tons) SO2 ( 1,000 tons) Mercury ( tons) Carbon ( MMT)

NERC Region Summer Annual Summer Annual Annual Annual Annual MECS 40 92 27 92 277 1.1 17 ECAO 228 544 177 842 2,510 8.4 123 ERCT 136 283 125 260 330 4.3 45 MACE 50 101 17 55 124 1.2 10 MACW 41 98 29 125 461 2.5 18 MACS 25 63 14 66 211 1.1 9 WUMS 26 59 19 65 192 1.0 13 MANO 88 206 52 226 706 4.5 38 MAPP 77 172 152 350 590 3.7 39 UPNY 53 120 17 49 188 1.1 9 LILC 6 14 1 3 0 0.3 1 NENG 49 118 16 44 133 1.5 12 FRCC 98 198 118 239 317 2.0 30 VACA 137 321 71 285 962 3.7 46 TVA 68 158 44 197 451 2.2 27 SOU 109 244 86 282 1,081 4.0 43 SPPN 43 95 56 160 185 1.4 21 SPPS 121 239 142 281 475 2.7 41 CNV 121 274 31 73 50 1.2 21 WSCP 76 181 17 39 124 0.4 8 WSCR 108 249 177 416 293 2.7 51 TOTAL 1,699 3,831 1,386 4,147 9,658 50.9 621 2 21 Exhibit 2 10 Future Mercury Air Emissions under the Base Case For the Electric Power Industry by Electric Generation Source ( Tons) Fuel Type 2005 2007 2010 Coal 47.9 48.0 46.9 Oil/ Gas Steam 0.03 0.03 0.00 Renewables 4.0 4.0 4.0 Total 51.9 52.0 50.9 Fossil Fuel Choices Examining the fossil fuel requirements of the electric power industry over time provides some interesting insights into how the industry will operate. Exhibit 2 12 shows IPM's forecast of future coal consumption to meet forecasted electric demand from 2005 to 2010 ( see Exhibit 2 11 for geographic coverage of each coal supply region). Although total consumption grows, the rate of growth varies among major supply regions. The greatest rate of growth is for western coal that has a low sulfur content and is increasingly cheaper to mine and ship over time. There is a forecasted decline in consumption from Northern Appalachia and the Midwest.

Exhibit 2 13 shows the changes in natural gas and oil use over time. IPM shows a significant increase in natural gas consumption for electric power generation. This occurs because a large amount of future electric demand growth will be met by combined cycle generation units that use natural gas. This technology is more energy efficient than coal fired generation and oil/ gas steam generation. Combined cycle natural gas units provide no emissions of SO2, trace amounts of mercury, limited amounts of NOx, and about two thirds of the carbon emissions of coal for every Btu consumed. The model forecasts that electric generation units will no longer use oil after 2005. 2 22 Exhibit 2 11 Coal Region Map West ND ME MW MP WP WG CG UC US CU CD NR CR NS AZ IA MO KS OK AN AS TX LA AS AL TN IL IN KW KE OH PC PW WN WS VA WA CS Western Northern Great Plains Eastern Northern Great Plains Northwest Rockies Central West Gulf Mid West Northern Appalachia Southern Appalachia Central Appalachia Southwest MD 2 23 Exhibit 2 12 Future Coal Consumption under the Base Case For the Electric Power Industry ( Million tons) Coal Supply Areas 2005 2007 2010 Northern Appalachia 138 138 109 Central and Southern Appalachia 185 186 213 Midwest 125 120 109 West 503 511 540 Central West and Gulf 64 64 63 Total 1,015 1,019 1,034 Exhibit 2 13 Future Natural Gas and Oil Consumption under the Base Case For the Electric Power Industry Fuel Units 2005 2007 2010 Natural Gas Trillion cubic feet 4.6 5.2 5.3 Oil Million Barrels 21.3 21.5 0


[Federal Register Volume 79, Number 49 (Thursday, March 13, 2014)]
[Rules and Regulations]
[Pages 14180-14182]
[FR Doc No: 2014-05442]

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DEPARTMENT OF HOMELAND SECURITY

Federal Emergency Management Agency

44 CFR Part 12

[Docket ID: FEMA-2014-0011]
RIN 1660-AA81

Removal of Federal Advisory Committee Act Regulations

AGENCY: Federal Emergency Management Agency, DHS.

ACTION: Final rule.

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SUMMARY: This final rule removes the regulations that implement the
Federal Advisory Committee Act (FACA) for the Federal Emergency
Management Agency (FEMA). FEMA's implementation of FACA is now governed
by the rules promulgated by the General Services Administration (GSA)
and by the policies issued by the Department of Homeland Security
(DHS).

DATES: Effective Date: April 14, 2014.

FOR FURTHER INFORMATION CONTACT:
    Program Information: Demaris Belanger, Group Federal Officer (GFO),
Office of the Chief Administrative Officer, Mission Support Bureau,
Federal Emergency Management Agency, Room 706-A, 500 C Street SW.,
Washington, DC 20472-3000, phone:<PHONE_NUMBER>, email:
<EMAIL_ADDRESS>    Legal Information: Michael Delman, Attorney Advisor, Office of
Chief Counsel, Federal Emergency Management Agency, 8NE, 500 C Street
SW., Washington, DC 20472-3100, phone:<PHONE_NUMBER>, email:
<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

I. Background

    The Federal Advisory Committee Act \1\ of 1972 (FACA) governs the
establishment, operation, oversight, and termination of advisory
committees within the executive branch of the Federal Government. With
certain exceptions, an advisory committee is ``any committee, board,
commission, council, conference, panel, task force, or other similar
group, or any subcommittee or other subgroup thereof'' established or
utilized by the President or one or more agencies, or established by
statute, for the purpose of obtaining advice or recommendations.\2\
FACA includes requirements that each advisory committee have a charter
and that meetings be open to the public, subject to certain limited
exceptions.\3\ FACA also establishes a Committee Management Secretariat
within the General Services Administration (GSA) that is responsible
for all matters related to advisory committees.\4\ Pursuant to
Executive Order 12024, the Administrator of GSA has been delegated all
of the functions vested in the President by FACA. FACA requires that
each agency establish uniform administrative guidelines and management
controls for advisory committees established by the agency.\5\ The
Federal Emergency Management

Agency (FEMA) implemented the requirements of FACA through regulations
published at 44 CFR part 12 titled ``Advisory Committees'' on September
29, 1980.\6\ FEMA has made subsequent technical changes, but has made
no substantive changes to the rule.\7\
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    \1\ Public Law 92-463, 86 Stat. 770 (Oct. 6, 1972), as amended,
5 U.S.C. App.
    \2\ Sec. 3, Public Law 92-463, as amended, 5 U.S.C. App.
    \3\ Secs. 9, 10, Public Law 92-463, as amended, 5 U.S.C. App.
    \4\ Sec. 7, Public Law 92-463, as amended, 5 U.S.C. App.
    \5\ Sec. 8, Public Law 92-463, as amended, 5 U.S.C. App.
    \6\ 45 FR 64179, Sep. 29, 1980.
    \7\ See 47 FR 13148, 13149-50, Mar. 29, 1982; 48 FR 44541,
44543, Sept. 29, 1983; 49 FR 33878, 33879, Aug. 27, 1984; 50 FR
40004, 40007, Oct. 1, 1985; 74 FR 15328, 15337-8, Apr. 3, 2009.
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    On April 28, 1983, GSA published an interim final rule providing
administrative and interpretative guidelines for Federal agencies on
the implementation of FACA \8\, followed by a final rule on December 2,
1987.\9\ GSA published another final rule on October 5, 1989 to clarify
aspects of the 1987 rule.\10\ In 1997, GSA determined that the 1987 and
1989 regulations had become out-of-date as a result of significant
decisions issued by the Supreme Court and other Federal Courts. On June
10, 1997, GSA issued an Advance Notice of Proposed Rulemaking to seek
input on a proposed revision.\11\ GSA published a proposed rule on
January 14, 2000 \12\ and a final rule on July 19, 2001.\13\ The 2001
GSA FACA rule is codified at 41 CFR part 102-3. The rule ``provides the
policy framework that must be used by agency heads in applying the
Federal Advisory Committee Act.'' 41 CFR 102-3.5.
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    \8\ 48 FR 19324, Apr. 28, 1983.
    \9\ 52 FR 45926, Dec. 2, 1987.
    \10\ 54 FR 41214, Oct. 5, 1989.
    \11\ 62 FR 31550, June 10, 1997.
    \12\ 65 FR 2504, Jan. 14, 2000.
    \13\ 66 FR 37728, July 19, 2001.
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II. Discussion of the Rule

    This rule removes FEMA's regulations implementing FACA at 44 CFR
part 12. FEMA's regulations implementing FACA are obsolete. Since FEMA
promulgated its rule in 1980, GSA has promulgated several rules,
including the 2001 rule setting up the framework for advisory
committees throughout the executive branch of the Federal Government.
GSA's rule includes detailed requirements for advisory committees along
with appendices that contain key points and principles answering
frequently asked questions on Federal advisory committees.
    In addition, FEMA, as a part of the Department of Homeland Security
(DHS), follows the policies of DHS. FEMA was an independent agency when
it promulgated its rule in 1980, but became part of DHS in 2003.\14\
DHS has an internal directive governing committee management; that
directive is available on the web at http://www.dhs.gov/xlibrary/assets/foia/mgmt_directive_2300_committee_management.pdf. FEMA
follows the DHS directive for the management of its advisory
committees. This removal of part 12 reflects FEMA's existing practice
of following GSA's regulations and DHS policies, rather than the
obsolete part 12 regulations.
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    \14\ Homeland Security Act of 2002, Public Law 107-296, 116
Stat. 2135 (Nov. 25, 2002). See also 6 U.S.C. 313 (``There is in the
Department [of Homeland Security] the Federal Emergency Management
Agency.'')
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III. Regulatory Analyses

A. Administrative Procedure Act

    The Administrative Procedure Act (APA) generally requires an agency
to publish a rule for public comment prior to implementation. 5 U.S.C.
553. The APA, however, provides an exception to this requirement for
rules of agency procedure or practice. 5 U.S.C. 553(b)(3)(A). FEMA's
removal of 44 CFR part 12 is related to FEMA's internal procedures.
This rule addresses the internal procedures that FEMA uses for advisory
committees, and it is limited to the requirements on FEMA for setting
up and administering FACA committees. This rule falls within the APA's
exception for rules of agency procedure or practice.

B. Executive Order 12866, Regulatory Planning and Review and Executive
Order 13563, Improving Regulation and Regulatory Review

    Executive Orders 13563 and 12866 direct agencies to assess the
costs and benefits of available regulatory alternatives and, if
regulation is necessary, to select regulatory approaches that maximize
net benefits (including potential economic, environmental, public
health and safety effects, distributive impacts, and equity). Executive
Order 13563 emphasizes the importance of quantifying both costs and
benefits, of reducing costs, of harmonizing rules, and of promoting
flexibility. This rule has not been designated a ``significant
regulatory action,'' under section 3(f) of Executive Order 12866.
Accordingly, the rule has not been reviewed by the Office of Management
and Budget. As explained in the background section, this rule is a
removal of an obsolete part of 44 CFR. It will make no substantive
changes to FEMA policies and procedures. This rule imposes no
regulatory costs on the public. FEMA reviewed its regulations and
determined that part 12 is outmoded. Therefore, FEMA has decided that
it should repeal its advisory committee regulations and rely on the GSA
rule and DHS guidance.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) (5 U.S.C. 601-612), and
section 213(a) of the Small Business Regulatory Enforcement Fairness
Act of 1996, Public Law 104-121, 110 Stat. 847, 858-9 (Mar. 29, 1996)
(5 U.S.C. 601 note) require that special consideration be given to the
effects of proposed regulations on small entities. The RFA mandates
that an agency conduct an RFA analysis when an agency is ``required by
section 553 . . ., or any other law, to publish general notice of
proposed rulemaking for any proposed rule[.]'' 5 U.S.C. 603(a).
Accordingly, an RFA is not required when a rule is exempt from notice
and comment rulemaking. FEMA has determined that this rule is exempt
from notice and comment rulemaking. Therefore, an RFA analysis under 5
U.S.C. 603 is not required for this rule.

D. Unfunded Mandates Reform Act

    FEMA has not issued a notice of proposed rulemaking for this
regulatory action; therefore, the provisions of the Unfunded Mandates
Reform Act of 1995, as amended, 2 U.S.C. 658, 1501-1504, 1531-1536,
1571, do not apply to this regulatory action.

E. Paperwork Reduction Act (PRA) of 1995

    As required by the Paperwork Reduction Act of 1995 (PRA), Public
Law 104-13, 109 Stat. 163 (May 22, 1995) (44 U.S.C. 3501 et seq.), an
agency may not conduct or sponsor, and a person is not required to
respond to, a collection of information unless the collection of
information displays a valid control number. FEMA has determined that
this rulemaking does not require any collection of information under
the Paperwork Reduction Act.

F. National Environmental Policy Act (NEPA) of 1969

    Section 102 of the National Environmental Policy Act of 1969
(NEPA), Public Law 91-190, 83 Stat. 852 (Jan. 1, 1970) (42 U.S.C. 4321
et seq.) requires agencies to consider the impacts in their decision-
making on the quality of the human environment. The Council on
Environmental Quality's procedures for implementing NEPA, 40 CFR parts
1500 through 1508, require Federal agencies to prepare Environmental
Impact Statements (EIS) for major federal actions significantly
affecting the quality of the human environment. Each agency can develop

categorical exclusions to cover actions that typically do not trigger
significant impacts to the human environment individually or
cumulatively. Agencies develop environmental assessments (EA) to
evaluate those actions that do not fit an agency's categorical
exclusion and for which the need for an EIS is not readily apparent. At
the end of the EA process, the agency will determine whether to make a
Finding of No Significant Impact or whether to initiate the EIS
process.
    Rulemaking is a major federal action subject to NEPA. However, FEMA
has categorically excluded certain actions from the preparation of an
EIS or EA, unless extraordinary circumstances exist. As applicable
here, 44 CFR 10.8(d)(2)(ii) exempts the preparation, revision, and
adoption of regulations from the preparation of an EA or EIS if the
rule relates to an action that qualifies for a categorical exclusion.
Administrative actions are categorically excluded from NEPA. 44 CFR
10.8(d)(2)(i). Because this is a rulemaking related to an
administrative function and no extraordinary circumstances exist, no EA
or EIS will be prepared.

G. Executive Order 13175, Consultation and Coordination With Indian
Tribal Governments

    Executive Order 13175, ``Consultation and Coordination With Indian
Tribal Governments,'' (65 FR 67249, Nov. 9, 2000), applies to agency
regulations that have Tribal implications, that is, regulations that
have substantial direct effects on one or more Indian tribes, on the
relationship between the Federal Government and Indian Tribes, or on
the distribution of power and responsibilities between the Federal
Government and Indian Tribes. Under this Executive Order, to the extent
practicable and permitted by law, no agency shall promulgate any
regulation that has Tribal implications, that imposes substantial
direct compliance costs on Indian Tribal governments, and that is not
required by statute, unless funds necessary to pay the direct costs
incurred by the Indian Tribal government or the Tribe in complying with
the regulation are provided by the Federal Government, or the agency
consults with Tribal officials. FEMA has determined that this
rulemaking will not have tribal implications.

H. Executive Order 13132, Federalism

    A rule has implications for federalism under Executive Order 13132,
``Federalism'' (64 FR 43255, Aug. 10, 1999), if it has a substantial
direct effect on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government. This
rulemaking does not have federalism implications.

I. Executive Order 12898, Environmental Justice

    Under Executive Order 12898, as amended, ``Federal Actions To
Address Environmental Justice in Minority Populations and Low-Income
Populations'' (59 FR 7629, Feb. 16, 1994), FEMA incorporates
environmental justice into its policies and programs. Executive Order
12898 requires each Federal agency to conduct its programs, policies,
and activities that substantially affect human health or the
environment, in a manner that ensures that those programs, policies,
and activities do not have the effect of excluding persons from
participation in, denying persons the benefit of, or subjecting persons
to discrimination because of their race, color, national origin or
income level.
    No action that FEMA can anticipate under this rule will have a
disproportionately high and adverse human health or environmental
effect on any segment of the population.

J. Executive Order 12988, Civil Justice Reform

    This rule meets applicable standards in sections 3(a) and 3(b)(2)
of Executive Order 12988, ``Civil Justice Reform'' (61 FR 4729, Feb. 9,
1996), to minimize litigation, eliminate ambiguity, and reduce burden.

K. Congressional Review Act

    FEMA has sent this final rule to the Congress and to the Government
Accountability Office under the Congressional Review of Agency
Rulemaking Act, (``Congressional Review Act''), Public Law 104-121, 110
Stat. 847 (Mar. 29, 1996) (5 U.S.C. 801 et seq.). This rule is not a
``major rule'' within the meaning of the Congressional Review Act. It
will not have an annual effect on the economy of $100,000,000 or more;
it will not result in a major increase in costs or prices for
consumers, individual industries, Federal, State, or local government
agencies, or geographic regions; and it will not have significant
adverse effects on competition, employment, investment, productivity,
innovation, or on the ability of United States-based enterprises to
compete with foreign-based enterprises in domestic and export markets.

List of Subjects in 44 CFR Part 12

    Advisory committees.
    For the reasons discussed in the preamble, and under the authority
of the Homeland Security Act of 2002, 6 U.S.C. 101 et seq., and the
Federal Advisory Committee Act, 5 U.S.C. App., the Federal Emergency
Management Agency amends 44 CFR Chapter I, subchapter A, as follows:

PART 12--[REMOVED AND RESERVED]

0
1. Remove and reserve part 12, consisting of Sec. Sec.  12.1 through
12.19.

    Dated: March 6, 2014.
W. Craig Fugate,
Administrator, Federal Emergency Management Agency.
[FR Doc. 2014-05442 Filed 3-12-14; 8:45 am]
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[Federal Register Volume 78, Number 14 (Tuesday, January 22, 2013)]
[Rules and Regulations]
[Page 4341]
[FR Doc No: 2013-01081]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[EPA-R08-OAR-2011-0114; FRL-9771-9]

Approval, Disapproval and Promulgation of State Implementation
Plans; State of Utah; Regional Haze Rule Requirements for Mandatory
Class I Areas Under 40 CFR 51.309; Correction

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule; correction.

-----------------------------------------------------------------------

SUMMARY: The EPA is supplementing the preamble to the final rule that
appeared in the Federal Register on December 14, 2012. This final rule
partially approved and partially disapproved a State Implementation
Plan (SIP) revision submitted by the State of Utah on May 26, 2011 that
addresses regional haze. The final rule preamble inadvertently did not
include language pertaining to judicial review, and this document adds
that language.

DATES: Effective on January 14, 2013.

FOR FURTHER INFORMATION CONTACT: Laurel Dygowski, Air Program, Mailcode
8P-AR, Environmental Protection Agency, Region 8, 1595 Wynkoop Street,
Denver, Colorado 80202-1129,<PHONE_NUMBER><EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: In Federal Register document 2012-29406
published in the Federal Register on December 14, 2012 (77 FR 74355),
the following corrections are made:
    1. On page 74372, in the first column, in section V. Statutory and
Executive Order Reviews, paragraph L. is added to read as follows: ``L.
Judicial Review--Under section 307(b)(1) of the Clean Air Act,
petitions for judicial review of this action must be filed in the
United States Court of Appeals for the appropriate circuit by March 25,
2013. Filing a petition for reconsideration by the Administrator of
this final rule does not affect the finality of this action for the
purposes of judicial review nor does it extend the time within which a
petition for judicial review may be filed, and shall not postpone the
effectiveness of such rule or action. This action may not be challenged
later in proceedings to enforce its requirements. (See CAA section
307(b)(2).)''

    Dated: December 20, 2012.
James B. Martin,
Regional Administrator, Region 8.
[FR Doc. 2013-01081 Filed 1-18-13; 8:45 am]
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[Federal Register Volume 82, Number 199 (Tuesday, October 17, 2017)]
[Notices]
[Page 48220]
[FR Doc No: 2017-22471]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. EL18-10-000]

Bloom Energy Corporation; Notice of Petition for Declaratory
Order

    Take notice that on October 10, 2017, pursuant to section 385.207
of the Federal Energy Regulatory Commission's (Commission) Rules of
Practice and Procedure, 18 CFR 292.205(c) and 385.207 (2017), Bloom
Energy Corporation (Bloom) filed a petition for declaratory order
requesting that the Commission declare that certain Bloom facilities,
which have internalized the hydrogen producing second-use process, meet
the Commission's standards for cogeneration units as set forth in 18
CFR 292.205(a)(1)-(2) and 18 CFR 292.205(d) of the Commission's
regulations, all as more fully explained in the petition.
    Any person desiring to intervene or to protest in this proceeding
must file in accordance with Rules 211 and 214 of the Commission's
Rules of Practice and Procedure (18 CFR 385.211 and 385.214) on or
before 5:00 p.m. Eastern time on the specified comment date. Protests
will be considered by the Commission in determining the appropriate
action to be taken, but will not serve to make protestants parties to
the proceeding. Any person wishing to become a party must file a notice
of intervention or motion to intervene, as appropriate. Such notices,
motions, or protests must be filed on or before the comment date.
Anyone filing a motion to intervene or protest must serve a copy of
that document on the Petitioner.
    The Commission encourages electronic submission of protests and
interventions in lieu of paper, using the FERC Online links at http://www.ferc.gov. To facilitate electronic service, persons with Internet
access who will eFile a document and/or be listed as a contact for an
intervenor must create and validate an eRegistration account using the
eRegistration link. Select the eFiling link to log on and submit the
intervention or protests.
    Persons unable to file electronically should submit an original and
5 copies of the intervention or protest to the Federal Energy
Regulatory Commission, 888 First Street NE., Washington, DC 20426.
    The filings in the above proceeding are accessible in the
Commission's eLibrary system by clicking on the appropriate link in the
above list. They are also available for review in the Commission's
Public Reference Room in Washington, DC. There is an eSubscription link
on the Web site that enables subscribers to receive email notification
when a document is added to a subscribed docket(s). For assistance with
any FERC Online service, please email<EMAIL_ADDRESS>or
call<PHONE_NUMBER> (toll free). For TTY, call<PHONE_NUMBER>.
    Comment Date: 5:00 p.m. Eastern time on November 9, 2017.

    Dated: October 11, 2017.
Kimberly D. Bose,
Secretary.
[FR Doc. 2017-22471 Filed 10-16-17; 8:45 am]
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[Federal Register Volume 81, Number 154 (Wednesday, August 10, 2016)]
[Notices]
[Pages 52889-52890]
[FR Doc No: 2016-18974]

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DEPARTMENT OF HOMELAND SECURITY

Federal Emergency Management Agency

[Docket ID FEMA-2016-0002; Internal Agency Docket No. FEMA-B-1634]

Proposed Flood Hazard Determinations

AGENCY: Federal Emergency Management Agency, DHS.

ACTION: Notice.

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SUMMARY: Comments are requested on proposed flood hazard
determinations, which may include additions or modifications of any
Base Flood Elevation (BFE), base flood depth, Special Flood Hazard Area
(SFHA) boundary or zone designation, or regulatory floodway on the
Flood Insurance Rate Maps (FIRMs), and where applicable, in the
supporting Flood Insurance Study (FIS) reports for the communities
listed in the table below. The purpose of this notice is to seek
general information and comment regarding the preliminary FIRM, and
where applicable, the FIS report that the Federal Emergency Management
Agency (FEMA) has provided to the affected communities. 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). In addition, the FIRM and FIS
report, once effective, will be used by insurance agents and others to
calculate appropriate flood insurance premium rates for new buildings
and the contents of those buildings.

DATES: Comments are to be submitted on or before November 8, 2016.

ADDRESSES: The Preliminary FIRM, and where applicable, the FIS report
for each community are available for inspection at both the online
location and the respective Community Map Repository address listed in
the tables below. Additionally, the current effective FIRM and FIS
report for each community are accessible online through the FEMA Map
Service Center at www.msc.fema.gov for comparison.
    You may submit comments, identified by Docket No. FEMA-B-1634, to
Rick Sacbibit, Chief, Engineering Services Branch, Federal Insurance
and Mitigation Administration, FEMA, 400 C Street SW., Washington, DC
20472,<PHONE_NUMBER>, or (email<EMAIL_ADDRESS>
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_ADDRESS>or visit the FEMA Map Information
eXchange (FMIX) online at www.floodmaps.fema.gov/fhm/fmx_main.html.

SUPPLEMENTARY INFORMATION: FEMA proposes to make flood hazard
determinations for each community listed below, in accordance with
section 110 of the Flood Disaster Protection Act of 1973, 42 U.S.C.
4104, and 44 CFR 67.4(a).
    These proposed 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. These flood
hazard determinations are used to meet the floodplain management
requirements of the NFIP and also are used to calculate the appropriate
flood insurance premium rates for new buildings built after the FIRM
and FIS report become effective.
    The communities affected by the flood hazard determinations are
provided in the tables below. Any request for reconsideration of the
revised flood hazard information shown on the Preliminary FIRM and FIS
report that satisfies the data requirements outlined in 44 CFR 67.6(b)
is considered an appeal. Comments unrelated to the flood hazard
determinations also will be considered before the FIRM and FIS report
become effective.
    Use of a Scientific Resolution Panel (SRP) is available to
communities in support of the appeal resolution process. SRPs are
independent panels of experts in hydrology, hydraulics, and other
pertinent sciences established to

review conflicting scientific and technical data and provide
recommendations for resolution. Use of the SRP only may be exercised
after FEMA and local communities have been engaged in a collaborative
consultation process for at least 60 days without a mutually acceptable
resolution of an appeal. Additional information regarding the SRP
process can be found online at http://floodsrp.org/pdfs/srp_fact_sheet.pdf.
    The watersheds and/or communities affected are listed in the tables
below. The Preliminary FIRM, and where applicable, FIS report for each
community are available for inspection at both the online location and
the respective Community Map Repository address listed in the tables.
For communities with multiple ongoing Preliminary studies, the studies
can be identified by the unique project number and Preliminary FIRM
date listed in the tables. Additionally, the current effective FIRM and
FIS report for each community are accessible online through the FEMA
Map Service Center at www.msc.fema.gov for comparison.

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

    Dated: August 2, 2016.
Roy E. Wright,
Deputy Associate Administrator for Insurance and Mitigation, Department
of Homeland Security, Federal Emergency Management Agency.

I. Non-watershed-based studies:

------------------------------------------------------------------------
                                             Community map repository
               Community                             address
------------------------------------------------------------------------
             Montgomery County, New York (All Jurisdictions)
------------------------------------------------------------------------
      Maps Available for Inspection Online at: http://www.fema.gov/preliminaryfloodhazarddata preliminaryfloodhazarddata
------------------------------------------------------------------------
        Project: 16-02-0009S Preliminary Date: February 19, 2016
------------------------------------------------------------------------
City of Amsterdam......................  City Hall, 61 Church Street,
                                          Amsterdam, NY 12010.
Town of Amsterdam......................  Amsterdam Town Office Building,
                                          283 Manny's Corners Road,
                                          Amsterdam, NY 12010.
Town of Canajoharie....................  Canajoharie Town Office, 12
                                          Mitchell Street, Canajoharie,
                                          NY 13317.
Town of Charleston.....................  Charleston Municipal Building,
                                          480 Corbin Hill Road,
                                          Sprakers, NY 12166.
Town of Florida........................  Florida Town Office Building,
                                          214 Fort Hunter Road,
                                          Amsterdam, NY 12010.
Town of Glen...........................  Glen Town Office, 7 Erie
                                          Street, Fultonville, NY 12072.
Town of Minden.........................  Minden Municipal Town Building,
                                          134 Highway 80, Fort Plain, NY
                                          13339.
Town of Mohawk.........................  Town of Mohawk, Richard A. Papa
                                          Office Building, 2-4 Park
                                          Street, Fonda, NY 12068.
Town of Palatine.......................  Palatine Town Office, 141 West
                                          Grand Street, Palatine Bridge,
                                          NY 13428.
Town of Root...........................  Root Town Office, 1048 Carlisle
                                          Road, Sprakers, NY 13317.
Town of St. Johnsville.................  St. Johnsville Town Office,
                                          7431 State Highway 5, St.
                                          Johnsville, NY 13452.
Village of Ames........................  Village Office, 595 Latimer
                                          Hill Road, Ames, NY 13317.
Village of Canajoharie.................  Canajoharie Village Office, 75
                                          Erie Boulevard, Canajoharie,
                                          NY 13317.
Village of Fonda.......................  Municipal Building, 8 East Main
                                          Street, Fonda, NY 12068.
Village of Fort Johnson................  Municipal Building, 1 Prospect
                                          Street, Fort Johnson, NY
                                          12070.
Village of Fort Plain..................  Village Hall, 168 Canal Street,
                                          Fort Plain, NY 13339.
Village of Fultonville.................  Village Court Municipal
                                          Building, 10 Erie Street,
                                          Fultonville, NY 12072.
Village of Hagaman.....................  Pawling Hall, 86 Pawling
                                          Street, Hagaman, NY 12086.
Village of Nelliston...................  Village Municipal Building, 11
                                          River Street, Nelliston, NY
                                          13410.
Village of Palatine Bridge.............  Village Office, 11 West Grand
                                          Street, Palatine Bridge, NY
                                          13428.
Village of St. Johnsville..............  St. Johnsville Village Office,
                                          16 Washington Street, St.
                                          Johnsonville, NY 13452.
------------------------------------------------------------------------
              Niagara County, New York (All Jurisdictions)
------------------------------------------------------------------------
      Maps Available for Inspection Online at: http://www.fema.gov/preliminaryfloodhazarddata preliminaryfloodhazarddata
------------------------------------------------------------------------
           Project: 16-02-0007S Preliminary Date: May 9, 2016
------------------------------------------------------------------------
Town of Pendleton......................  Pendleton Town Hall, 6570
                                          Campbell Boulevard, Lockport,
                                          NY 14094.
------------------------------------------------------------------------
               Butler County, Ohio and Incorporated Areas
------------------------------------------------------------------------
      Maps Available for Inspection Online at: http://www.fema.gov/preliminaryfloodhazarddata preliminaryfloodhazarddata
------------------------------------------------------------------------
 Project: 15-05-6384S Preliminary Dates: April 25, 2014 & September 18,
                                  2015
------------------------------------------------------------------------
City of Fairfield......................  City Hall, 5350 Pleasant
                                          Avenue, Fairfield, OH 45014.
City of Hamilton.......................  Department of Community
                                          Development, Planning
                                          Division, 345 High Street,
                                          Suite 370, Hamilton, OH 45011.
------------------------------------------------------------------------

[FR Doc. 2016-18974 Filed 8-9-16; 8:45 am]
 BILLING CODE 9110-12-P