[Federal Register: April 9, 2009 (Volume 74, Number 67)]
[Notices]
[Page 16204-16205]
[DOCID:fr09ap09-53]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket Nos. EL08-14-002]

Black Oak Energy, LLC, EPIC Merchant Energy, LP, SESCO
Enterprises, LLC, Joint Complainants v. PJM Interconnection, Inc.,
Respondent; Notice of Filing

April 2, 2009.
    Take notice that on March 26, 2009, PJM Interconnection, L.L.C.
submit revised PJM Open Access Transmission Tariff and PJM Amended and
Restated Operating Agreement sheets, in compliance with the
Commission's February 24, 2009 Order, Black Oak Energy, et al. v. PJM
Interconnection, L.L.C., 126 FERC ] 61,164 (2009) (February 24 Order).
    Any person desiring to intervene or to protest this filing must
file in accordance with Rules 211 and 214 of the Commission's Rules of
Practice and Procedure (18 CFR 385.211, 385.214). Protests will be
considered by the Commission in determining the appropriate action to
be taken, but will not serve to make protestants parties to the
proceeding. Any person wishing to become a party must file a notice of
intervention or motion to intervene, as appropriate. Such notices,
motions, or protests must be filed on or before the comment date.
Anyone filing a motion to intervene or protest must serve a copy

of that document on the Applicant and all the parties in this
proceeding.
    The Commission encourages electronic submission of protests and
interventions in lieu of paper using the ``eFiling'' link at http://
www.ferc.gov. Persons unable to file electronically should submit an
original and 14 copies of the protest or intervention to the Federal
Energy Regulatory Commission, 888 First Street, NE., Washington, DC
20426.
    This filing is accessible on-line at http://www.ferc.gov, using the
``eLibrary'' link and is available for review in the Commission's
Public Reference Room in Washington, DC. There is an ``eSubscription''
link on the Web site that enables subscribers to receive e-mail
notification when a document is added to a subscribed docket(s). For
assistance with any FERC Online service, please e-mail
<EMAIL_ADDRESS>or call<PHONE_NUMBER> (toll free). For
TTY, call<PHONE_NUMBER>.
    Comment Date: 5 pm Eastern Time on April 16, 2009.

Kimberly D. Bose,
Secretary.
[FR Doc. E9-8052 Filed 4-8-09; 8:45 am]

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[Federal Register: April 8, 2009 (Volume 74, Number 66)]
[Rules and Regulations]
[Page 15842-15843]
[DOCID:fr08ap09-5]

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DEPARTMENT OF TRANSPORTATION

Federal Aviation Administration

14 CFR Part 71

[Docket No. FAA-2008-1129; Airspace Docket No. 08-ANM-7]

Establishment of Class E Airspace; Ten Sleep, WY

AGENCY: Federal Aviation Administration (FAA), DOT.

ACTION: Final rule.

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SUMMARY: This action will establish Class E airspace at Ten Sleep, WY.
Additional controlled airspace is necessary to accommodate aircraft
using a new Area Navigation (RNAV) Global Positioning System (GPS)
Standard Instrument Approach Procedure (SIAP) at Red Reflet Ranch
Airport, Ten Sleep, WY. This will improve the safety of Instrument
Flight Rules (IFR) aircraft executing the new RNAV GPS SIAP at Red
Reflet Ranch Airport, Ten Sleep, WY.

DATES: Effective Date: 0901 UTC, July 2, 2009. The Director of the
Federal Register approves this incorporation by reference action under
1 CFR part 51, subject to the annual revision of FAA Order 7400.9 and
publication of conforming amendments.

FOR FURTHER INFORMATION CONTACT: Eldon Taylor, Federal Aviation
Administration, Operations Support Group, Western Service Center, 1601
Lind Avenue, SW., Renton, WA 98057; telephone<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:

History

    On February 13, 2009, the FAA published in the Federal Register a
notice of proposed rulemaking to establish controlled airspace at Ten
Sleep, WY (74 FR 7204). Interested parties were invited to participate
in this rulemaking effort by submitting written comments on the
proposal to the FAA. No comments were received.
    Class E airspace designations are published in paragraph 6005 of
FAA Order 7400.9S signed October 3, 2008, and effective October 31,
2008, which is incorporated by reference in 14 CFR part 71.1. The Class
E airspace designations listed in this document will be published
subsequently in that Order.

The Rule

    This action amends Title 14 Code of Federal Regulations (14 CFR)
part 71 by establishing Class E airspace at Ten Sleep, WY. Controlled
airspace is necessary to accommodate IFR aircraft executing new RNAV
(GPS) SIAPs at Red Reflet Ranch Airport, Ten Sleep, WY.
    The FAA has determined that this regulation only involves an
established body of technical regulations for which frequent and
routine amendments are necessary to keep them operationally current.
Therefore, this regulation: (1) Is not a ``significant regulatory
action'' under Executive Order 12866; (2) is not a ``significant rule''
under DOT Regulatory Policies and Procedures (44 FR 11034; February 26,
1979); and (3) does not warrant preparation of a regulatory evaluation
as the anticipated impact is so minimal. Since this is a routine matter
that will only affect air traffic procedures and air navigation, it is
certified that this rule, when promulgated, will not have a significant
economic impact on a substantial number of small entities under the
criteria of the Regulatory Flexibility Act. The FAA's authority to
issue rules regarding aviation safety is found in Title 49 of the U.S.
Code. Subtitle 1, Section 106 discusses the authority of the FAA
Administrator. Subtitle VII, Aviation Programs, describes in more
detail the scope of the agency's authority. This rulemaking is
promulgated under the authority described in Subtitle VII, Part A,
Subpart I, Section 40103. Under that section, the FAA is charged with
prescribing regulations to assign the use of airspace necessary to
ensure the safety of aircraft and the efficient use of airspace. This
regulation is within the scope of that authority as it establishes
controlled airspace at Red Reflet Ranch Airport, Ten Sleep, WY.

List of Subjects in 14 CFR Part 71

    Airspace, Incorporation by reference, Navigation (air).

Adoption of the Amendment

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

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

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

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

Sec.  71.1  [Amended]

0
2. The incorporation by reference in 14 CFR 71.1 of the Federal
Aviation Administration Order 7400.9S, Airspace

Designations and Reporting Points, signed October 3, 2008, and
effective October 31, 2008 is amended as follows:

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

* * * * *

ANM WY, E5 Ten Sleep, WY [New]

Ten Sleep, Red Reflet Ranch Airport, WY
    (Lat. 43[deg]58'04'' N., long. 107[deg]22'46'' W.)

    That airspace extending upward from 700 feet above the surface
within a 6.6 mile radius of the Red Reflet Ranch Airport, and within
4 miles each side of the Red Reflet Ranch Airport 293[deg] bearing
extending from the 6.6-mile radius to 12 miles northwest of the Red
Reflet Ranch Airport.
* * * * *

    Issued in Seattle, Washington, on March 31, 2009.
Steve Karnes,
Acting Manager, Operations Support Group, Western Service Center.
[FR Doc. E9-7900 Filed 4-7-09; 8:45 am]

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[Federal Register: January 27, 2010 (Volume 75, Number 17)]
[Proposed Rules]
[Page 4316-4323]
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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Chapter I

[Docket No. RM10-11-000]

Integration of Variable Energy Resources

Issued January 21, 2010.
AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of Inquiry.

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SUMMARY: In this Notice of Inquiry, the Federal Energy Regulatory
Commission (Commission) seeks comment on the extent to which barriers
may exist that impede the reliable and efficient integration of
variable energy resources (VERs) into the electric grid, and whether
reforms are needed to eliminate those barriers. In order to meet the
challenges posed by the integration of increasing numbers of VERs,
ensure that jurisdictional rates are just and reasonable, eliminate
impediments to open access transmission service for all resources,
facilitate the efficient development of infrastructure, and ensure that
the reliability of the grid is maintained, the Commission seeks to
explore whether reforms are necessary to ensure that wholesale
electricity tariffs are just, reasonable and not unduly discriminatory.
This Notice will enable the Commission to determine whether wholesale
electricity tariff reforms are necessary.

DATES: Comments are due March 29, 2010.

ADDRESSES: You may submit comments, identified by docket number by any
of the following methods:
     Agency Web site: http://ferc.gov. Documents created
electronically using word processing software should be filed in native
applications or print-to-PDF format and not in a scanned format.
     Mail/Hand Delivery: Commenters unable to file comments
electronically must mail or hand deliver an original and 14 copies of
their comments to: Federal Energy Regulatory Commission, Secretary of
the Commission, 888 First Street, NE., Washington, DC 20426.

FOR FURTHER INFORMATION CONTACT:
Mk Shean (Technical Information), Office of Energy Policy and
Innovations, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, DC 20426,<PHONE_NUMBER><EMAIL_ADDRESS>Timothy Duggan (Legal Information), Office of General Counsel--Energy
Markets, Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426,<PHONE_NUMBER><EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:
    1. In this Notice of Inquiry, the Federal Energy Regulatory
Commission (Commission) seeks comment on the extent to which barriers
exist that may impede the reliable and efficient integration of
variable energy resources (VERs) \1\ into the electric grid and

whether reforms are needed to eliminate those barriers. VERs, such as
resources powered by wind and solar energy, continue to make up an
increasing percentage of the nation's energy supply portfolio; however,
they present unique challenges (such as location constraints and
limited dispatchability) that are not typically presented by
conventional electricity generating resources. VERs also present
benefits, such as low marginal energy costs and reduced greenhouse gas
emissions, which have contributed to the accelerated development of
these resources. In order to meet these challenges and fully realize
these benefits of VERs in a reliable and efficient manner, the
Commission seeks to explore whether reforms of existing policies are
necessary to ensure that jurisdictional rates are just and reasonable
and that the terms of jurisdictional service do not unduly discriminate
against these resources.
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    \1\ For purposes of this proceeding, the term variable energy
resource (VER) refers to renewable energy resources that are
characterized by variability in the fuel source that is beyond the
control of the resource operator. This includes wind and solar
generation facilities and certain hydroelectric resources.
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I. Background

    2. While the amount of VERs remains relatively small as a
percentage of total generation, it is rapidly increasing, reaching a
point where such resources are becoming a significant component of the
nation's energy supply portfolio. In 2008, new wind generating
capacity, totaling 8,376 MW, made up 42 percent of all newly installed
generating capacity.\2\ Moreover, in recent years, a number of state
renewable portfolio standards and other incentives/mandates have been
passed to encourage the development of renewable energy resources, in
response to a growing concern about the environmental impacts and
sustainability of the Nation's current electricity supply portfolio. As
of December 2009, 30 states, including the District of Columbia, had a
renewable portfolio standard.\3\
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    \2\ Div. of Market Oversight, Fed. Energy Regulatory Comm'n,
2008 State of the Markets Report 19 (2009), available at http://
www.ferc.gov/market-oversight/st-mkt-ovr/2008-som-final.pdf.
    \3\ Div. of Market Oversight, Fed. Energy Regulatory Comm'n,
Renewable Power and Energy Efficiency Market: Renewable Portfolio
Standards 1 (2009), available at http://www.ferc.gov/market-
oversight/othr-mkts/renew/othr-rnw-rps.pdf.
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    3. While VERs have many desirable characteristics, including low
marginal energy costs and reduced greenhouse gas and other pollutant
emissions, compared to conventional fossil-fueled generation, they also
present unique challenges as public utilities work to integrate VERs in
a way that ensures system reliability. For example, because VERs cannot
control or store their fuel source, they have limited ability to
control their production of electricity, and the weather-related
phenomena that drive VER output levels can be difficult to forecast.
Also, the output from some VERs can be negatively correlated with
demand, such that a resource's greatest energy output often comes at a
time of limited energy demand. Changes in the rate of output from VERs
may also result in substantial ramps,\4\ which can require additional
resources to allow System Operators \5\ to balance generation and
demand while maintaining reliability in real time.
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    \4\ A ramp is the rate, expressed in megawatts per minute, that
a generator changes its output.
    \5\ System Operator refers to the individual at a control
center--balancing authority, transmission operator, generator
operator (VERs as well as conventional resources), or reliability
coordinator--whose responsibility it is to monitor and control the
electric system in real time.
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    4. In this proceeding, the Commission seeks to explore whether
existing rules, regulations, tariffs, or industry practices within the
Commission's jurisdiction may hinder the reliable and efficient
integration of VERs, resulting in rates that are unjust and
unreasonable and/or terms of service that unduly discriminate against
certain types of resources. The Commission seeks comment on how best to
reform any such rules, regulations, tariffs, or industry practices.
    5. Under sections 205 and 206 of the Federal Power Act, the
Commission has a responsibility to remedy undue discrimination with
respect to transmission of electric energy and sales of electric energy
for resale in interstate commerce and to ensure that rates for these
services are just and reasonable.\6\ As the electric power industry has
evolved, the Commission has discharged this responsibility in different
ways. In Order No. 888, the Commission exercised its authority to
remedy undue discrimination by requiring all public utilities to
provide open access transmission service consistent with the terms of a
pro forma open access transmission tariff (OATT).\7\ The pro forma OATT
addresses the terms of transmission service, including, among other
things, the terms for scheduling transmission service, curtailments,
and the provision of ancillary services. In Order No. 2003, the
Commission acted to remove barriers in the generator interconnection
process and adopted standard procedures (the Large Generation
Interconnection Procedures or LGIP), and a standard agreement (the
Large Generation Interconnection Agreement or LGIA) for the
interconnection of generation resources larger than 20 MW.\8\ More
recently, in a further effort to remedy the potential for undue
discrimination, the Commission revised and updated the pro forma OATT
in Order No. 890.\9\
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    \6\ 16 U.S.C. 824d, 824e.
    \7\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, FERC Stats. & Regs. ] 31,036 (1996), order on reh'g,
Order No. 888-A, FERC Stats. & Regs. ] 31,048, order on reh'g, Order
No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 888-C,
82 FERC ] 61,046 (1998), aff'd in relevant part sub nom.
Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C.
Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
    \8\ Standardization of Generator Interconnection Agreements and
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146 (2003),
order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ] 31,160,
order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ] 31,171
(2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. ]
31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util.
Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007). Similarly, the
Commission also adopted standard procedures for the interconnection
of small generation resources. Standardization of Small Generator
Interconnection Agreements and Procedures, Order No. 2006, FERC
Stats. & Regs. ] 31,180, order on reh'g, Order No. 2006-A, FERC
Stats. & Regs. ] 31,196 (2005), order granting clarification, Order
No. 2006-B, FERC Stats. & Regs. ] 31,221 (2006).
    \9\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, FERC Stats. & Regs. ] 31,241,
order on reh'g, Order No. 890-A, FERC Stats. & Regs. ] 31,261
(2007), order on reh'g, Order No. 890-B, 123 FERC ] 61,299 (2008),
order on reh'g, Order No. 890-C, 126 FERC ] 61,228, order on
clarification, Order No. 890-D, 129 FERC ] 61,126 (2009).
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    6. With limited exceptions,\10\ these and other Commission efforts
to remedy undue discrimination have not expressly accounted for the
differences between VERs and more conventional generation resources. In
large part this is due to the fact that the electric grid was developed
during a time when electricity was almost exclusively generated from
centralized, dispatchable resources that were powered by fuel sources
that could be stored and used as needed. The Commission's policies and
the concomitant implementation of its responsibility under sections 205
and 206 were premised on this underlying physical reality of the
electric grid.
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    \10\ See, e.g., Interconnection for Wind Energy, Order No. 661,
FERC Stats. & Regs. ] 31,186, order on reh'g, Order No. 661-A, FERC
Stats. & Regs. ] 31,198 (2005) (adopting reforms to the LGIA and
LGIP to establish standard technical requirements for
interconnection of wind plants); Order No. 890, FERC Stats. & Regs.
] 31,241 at P 665 (establishing a standard offer generation
imbalance service, but exempting intermittent resources from the
highest penalty band).
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    7. Where relevant, however, the Commission on several occasions has
taken the operational characteristics of

VERs into consideration in efforts to ensure just and reasonable rates
and to remedy undue discrimination. In Order No. 661, the Commission
required public utilities to revise their LGIAs and LGIPs to
incorporate standard technical requirements for the interconnection of
wind resources larger than 20 MW.\11\ In Order No. 890, the Commission
applied a reduced penalty amount to intermittent resources' imbalances
that would otherwise be subject to the highest-tier generation
imbalance penalties, recognizing ``that intermittent generators cannot
always accurately follow their schedules and that high penalties will
not lessen the incentive to deviate from their schedules.'' \12\ In
addition, in Order No. 890 the Commission created conditional firm
point-to-point transmission service, noting that conditional firm
service can be particularly beneficial to renewable energy
resources.\13\ Shortly after the issuance of Order No. 890, the
Commission accepted a unique cost allocation mechanism for
interconnection facilities connecting renewable energy resources that
are location-constrained, recognizing that the difficulties faced by
these resources are different from those faced by other generation
developers, and therefore support an appropriate variation of the
interconnection pricing policy.\14\
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    \11\ Order No. 661, FERC Stats. & Regs. ] 31,186 (adopting,
among other things, a low voltage ride-through standard, a power
factor range, dynamic reactive power capability, and supervisory
control and data acquisition (SCADA) capability).
    \12\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 664-65.
    \13\ Id. P 912.
    \14\ Cal. Indep. Sys. Operator Corp., 119 FERC ] 61,061, at P
69-70 (2007). See also Southwest Power Pool, Inc., 127 FERC ]
61,283, at P 29 (2009) (accepting a proposal to allocate network
upgrade costs differently for wind resources being used to serve
demand in a different zone than the methodology used for other
resources).
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    8. Such actions are premised on the notion that targeted revisions
to Commission policies are sometimes necessary to ensure that
jurisdictional rates are just and reasonable and to prevent undue
discrimination against any one type of customer or resource as the
characteristics of the nation's generation portfolio change.

II. Subject of the Notice of Inquiry

    9. In this proceeding, the Commission seeks to take a fresh look at
existing policies and practices in light of the changing
characteristics of the nation's generation portfolio with the aim of
removing unnecessary barriers to transmission service and wholesale
markets for VERs (and other technologies that may aid their
integration) and promoting greater efficiencies that ultimately will
reduce costs to consumers. While the Commission seeks comment on
numerous challenges presented by the integration of VERs, this
proceeding will not address issues related to transmission planning and
cost allocation, as the Commission is considering those issues in
another forum.\15\
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    \15\ Transmission Planning Processes Under Order No. 890, Docket
No. AD09-8-000 (Oct. 8, 2009) (notice of request for comments).
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    10. Our goal is not to adopt rules that favor one type of supply
source over another. Instead, the Commission's purpose in this
proceeding is to investigate market and operational reforms necessary
to achieve two goals: first, to ensure that rates for jurisdictional
service are just and reasonable, reflecting the implementation of
practices that increase the efficiency of providing service; and
second, to prevent VERs from facing undue discrimination. These goals
are consistent with the requirements of sections 205 and 206 of the
FPA.
    11. In addition, the Commission must ensure that any reforms are
consistent with the need to maintain system reliability in accordance
with Reliability Standards proposed by the North American Electric
Reliability Corp. (NERC) and approved by the Commission pursuant to
section 215 of the FPA.\16\ Although the scope of this proceeding is
directed to market and operational reforms, in certain instances where
commenters believe existing NERC Reliability Standards should be
modified or new standards developed in conjunction with the market
reforms considered herein, they may indicate as much, if directly
related to this proceeding. In responding to the following questions,
commenters should indicate how the reforms that they propose ensure the
reliable operation of the grid, or would impact the reliable operation
of the grid, as required by the reliability standards.\17\
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    \16\ 16 U.S.C. 824o.
    \17\ See id. at 824o(a)(3). We note that NERC has an ongoing
stakeholder process to examine how to accommodate high levels of
variable generation. See North American Elec. Reliability Corp.,
Accommodating High Levels of Variable Generation (2009).
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III. Questions for Response

    12. To ensure that all generation resources are afforded non-
discriminatory access to wholesale markets and the electric power grid
and that wholesale market prices and the rates for transmission service
are just and reasonable, the Commission seeks comment on the perceived
barriers, and suggested solutions to removing those barriers, of
integrating VERs into the electric grid in a reliable and efficient
manner. The Commission's preliminary view is that one of the most
important operational issues affecting the integration costs for VERs
involves the reserves necessary to address variability in VER output.
Addressing this issue means examining a number of operational practices
and processes that affect both the determination of the amount of
reserves needed as well as the cost of those reserves. The Commission
seeks comment on the impact of integrating an increasing number of VERs
in the following subject areas: (1) Data and reporting requirements,
including the use of accurate forecasting tools; (2) scheduling
practices, flexibility, and incentives for accurate scheduling of VERs;
(3) forward market structure and reliability commitment processes; (4)
balancing authority area coordination and/or consolidation; (5)
suitability of reserve products and reforms necessary to encourage the
efficient use of reserve products; (6) capacity market reforms; and,
(7) redispatch and curtailment practices necessary to accommodate VERs
in real time.
    13. The Commission does not seek to limit its inquiry and
encourages all comments regarding the topics broadly discussed herein.
Commenters are invited to share with the Commission their overall
thoughts, including technical, commercial, and legal observations, on
the challenges posed by the increasing number of VERs, operational and
technical barriers faced by VERs, and the extent to which Commission
policies can and/or should be revisited in light of the increasing
number of VERs. Where commenters believe specific revisions to
Commission rules and/or pro forma OATT provisions are necessary to
implement their proposed reforms, they are encouraged to cite those
rules and/or provisions with specificity and suggest revised language
as appropriate. In this Notice of Inquiry we seek information with
regard to whether changes to rules or practices as applied to VERs will
achieve the Commission's goals. However, there may be instances where a
change to a rule or practice could also assure just and reasonable
rates and address undue discrimination if applied to other resources.
Therefore, we ask commenters to address whether any proposed changes to
the Commission rules or OATT provisions should apply to all resources.
In

addition, the Commission seeks responses to the specific questions
listed below.

A. Data and Forecasting

    14. The scheduling and operational practices of the bulk power
system are predicated on the ability to predict, with relative
precision, the output of generation resources and the ability of
reserve products to accommodate fluctuations in demand and emergency
conditions. The rapid increase in the development of VERs has presented
the industry with a variety of challenges related to predicting the
exact output of VERs at any point in time.
    15. These challenges could become more manageable for System
Operators through the development and use of state-of-the-art
meteorological forecasts, which are supplied with data from multiple
diverse locations. Specifically, the implementation of enhanced
forecasting tools and procedures could assist in projecting the output
of VERs with greater accuracy, thereby promoting the efficient
scheduling of all generation resources to meet expected demand,
especially during the morning increase and evening decrease in demand.
Enhanced forecasting could also allow System Operators in all regions
to anticipate system ramping events more effectively and respond to
them in an economically efficient manner, thereby ensuring that
jurisdictional rates are just and reasonable.
    16. To assist in the development of state-of-the-art forecasting
tools for VERs, the Commission seeks comment on whether and, if so, how
the Commission should modify existing operational data reporting
requirements. The Commission also aims to determine what data and what
level of data-sharing is necessary, coupled with advanced communication
and metering tools, to ensure that VERs are integrated in a reliable
and efficient manner, particularly with respect to scheduling, ramping
needs, and the procurement of reserve services.
    17. To that end, the Commission seeks comment on the following
questions:
    1. What are the current practices used to forecast generation from
VERs? Will current practices in forecasting VERs' electricity
production be adequate as the number of VERs increases? If so, why?
    2. What is necessary to transition from the existing power
generation forecasting systems for wind and solar generation resources
to a state-of-the-art forecasting system? What type of data (e.g.,
meteorological, outage, etc.), sampling frequency, and sampling
location requirements are necessary to develop and integrate state-of-
the-art forecasts, and what technical or market barriers impede such
development?
    3. What data, forecasting tools and processes do System Operators
need to more effectively address ramping events and other variations in
VER output, and to validate enhanced forecasting tools and procedures?
    4. What operational, outage and meteorological data should the
Commission require VERs to provide to non-VER System Operators? To what
size resources, in MWs, should any such data requirements apply, and
what revisions to the pro forma OATT would be necessary to accommodate
these requirements?
    5. State-of-the-art forecasts may necessitate the sharing of
meteorological data across regions to assure that the movement of
weather patterns can be accurately predicted and analyzed. To what
extent should meteorological data be made publically available to aid
in the development of state-of-the-art forecasts? Should the Commission
require public utilities to maintain a meteorological data reporting
system? If so, should such a system be akin to or in collaboration with
Open Access Same Time Information System (OASIS) postings? In order to
retain the confidentiality of commercially sensitive data reported by
VERs for the purpose of developing state-of-the-art forecasts, what
limits and/or safeguards should be established to protect operational
data and generator outage reports?
    6. Should the Commission encourage both decentralized and
centralized meteorological and VER energy production forecasting? For
example, should transmission providers have independent forecasting
obligations as part of their reliability commitment processes similar
to what is done today for demand forecasting?
    7. To what extent is a lack of data regarding the operational
status and forecasted output of distributed, or behind-the-meter, VERs
leading to a need for additional reserves? To what extent would the
provision of such data reduce the need for System Operators to rely on
reserves?

B. Scheduling Flexibility and Scheduling Incentives

1. Scheduling Flexibility
    18. Existing scheduling practices were designed at a time when
virtually all generation on the system could be scheduled with relative
precision. With increasing numbers of VERs, System Operators appear to
be relying more on expensive reserves, such as regulation reserves, to
balance the variation in energy output from VERs. Improvements in
scheduling procedures may offer the potential for greater efficiency in
dispatching all energy resources if the degree of variability can be
reduced, better anticipated, and/or planned for more precisely.
    19. In regions outside of those run by regional transmission
organizations (RTOs) or independent system operators (ISOs), resources
typically schedule transmission service on an hourly basis and are only
allowed to adjust their schedules during the hour for emergency
situations that threaten reliability.\18\ Because transmission
schedules for VERs are typically set 20-30 minutes ahead of the hour,
the forecast of output may be 90 minutes old by the end of the
operating hour. Additionally, by limiting the ability of resources to
adjust their schedules during the hour or to submit shorter scheduling
timeframes, non-RTO/ISO System Operators may not be utilizing the full
operational flexibility of the resources on their systems to change
output levels to address the variable output of VERs.
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    \18\ Section 13.8 of the pro forma OATT requires transmission
customers to schedule use of firm point-to-point transmission
service by 10:00 a.m. the day prior to operation. However, section
13.8 of the pro forma OATT gives the transmission provider the
discretion to accept schedule changes no later than 20 minutes prior
to the operating hour.
---------------------------------------------------------------------------

    20. In RTOs/ISOs, real-time markets are employed to address
imbalance energy needs. Real-time markets utilize intra-hour economic
dispatch of internal resources, which affords RTOs/ISOs the ability to
respond quickly and economically to fluctuations in VER supply.
However, RTOs/ISOs often schedule external resources on an hourly
basis, consistent with non-RTO/ISO scheduling practices.
    21. The Commission questions whether the retention of existing
transmission scheduling practices as additional VERs come on-line is
causing rates for reserves (as part of transmission service) to become
unjust and unreasonable by inhibiting the ability of VERs to establish
operationally-viable schedules and preventing System Operators from
utilizing the full flexibility of their systems. Accordingly, the
Commission seeks to explore whether greater scheduling flexibility,
such as intra-hour scheduling, could provide benefits to the system and
facilitate the reliable and efficient use of all resources.
    22. To that end, the Commission seeks comment on the following
questions:
    1. Would shorter scheduling intervals allow System Operators to
more

efficiently manage the ramps of VERs and/or demand? To what extent
would the availability of intra-hour scheduling decrease the overall
reliance on regulation reserves to manage the variability of VERs?
    2. What are the benefits and costs of allowing resources and
transactions to schedule on an intra-hour basis, and what tariff and/or
technical barriers exist to implementing intra-hour scheduling? Are
there best practices that could be implemented to facilitate greater
intra-hour scheduling?
    3. Are there an optimum number of intervals within the hour for
scheduling? What time increments would be necessary and/or desirable in
order to achieve optimum flexibility while still meeting the relevant
reliability requirements?
    4. Identify any reliability issues that may result from changes to
the scheduling rules. What changes, if any, to NERC Reliability
Standards would be needed to fully implement additional scheduling
flexibility while still ensuring reliability?
    5. How would intra-hour scheduling affect the operation of other
processes such as available transfer capability (ATC), the E-Tag
system, issuance of dispatch instructions for generation and/or demand
resources, transmission loading relief procedures, and/or dynamic
schedules? What costs would be incurred as a result?
    6. If intra-hour scheduling is implemented in non-RTO/ISO regions,
how would RTO/ISO scheduling practices at interties be affected? Would
intra-hour scheduling at interties present problems for RTO/ISO
markets? If so, describe the problems and feasible solutions for intra-
hour scheduling at interties.
2. Scheduling Incentives
    23. Reforms to existing scheduling practices to promote intra-hour
scheduling could enable VERs to more accurately meet their schedules,
which in turn should help to ensure that rates for reserves are just
and reasonable. In order to achieve overall improvements in scheduling
accuracy, particularly with respect to VERs, it is also important to
ensure that such resources have the appropriate incentives to meet
their schedules with real-time output to the extent feasible.
    24. In Order No. 890, the Commission adopted pro forma OATT
imbalance provisions that implemented a graduated bandwidth approach to
imbalance penalties that recognized the link between escalating
deviations and potential reliability impacts on the system.\19\ The
Commission exempted intermittent resources from the third tier
deviation band, which required imbalances of greater than 7.5 percent
of scheduled amounts (or 10 MW) to be settled at 125 percent of the
incremental cost or 75 percent of the decremental cost of providing the
imbalance energy.\20\ Instead, intermittent resources with such
imbalances would only be subject to the second tier imbalance
penalties, i.e., 110 percent of the incremental or 90 percent of the
decremental cost.\21\ The Commission is interested in examining the
experience with this exemption to determine whether it has resulted in
scheduling practices that may result in an overall rate for
transmission service that is not just and reasonable.
---------------------------------------------------------------------------

    \19\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 663-64.
    \20\ Id. P 664-65.
    \21\ In RTOs/ISOs, because real-time markets are used to address
imbalance energy needs, VERs are typically exempt from some pro
forma OATT deviation penalties.
---------------------------------------------------------------------------

    25. To that end, the Commission seeks comment on the following
questions:
    1. Has the exemption from third-tier penalty imbalances worked as a
targeted exemption that recognizes operational limitations of VERs,\22\
or has it encouraged inefficient scheduling behaviors to develop? If
the latter, what reforms to this exemption would encourage more
accurate scheduling practices?
---------------------------------------------------------------------------

    \22\ For the purposes of this section, the term ``VERs'' refers
to the same resources that the Commission identified as
``intermittent'' in Order No. 890. Order No. 890, FERC Stats. &
Regs. ] 31,241 at P 666.
---------------------------------------------------------------------------

    2. Assuming that efficient forecasting and scheduling practices
help minimize deviations between scheduled and actual energy output of
VERs, are additional incentives needed to encourage VERs to submit
schedules that are informed by state-of-the-art forecasting? What would
be the proper incentives?
    3. Under an RTO/ISO market design, are there sufficient incentives
to encourage VERs to submit accurate schedules? What costs and/or
penalties should be assigned to VERs when their real-time output is not
accurately scheduled on a forward basis? Should VERs be treated the
same as conventional resources with respect to deviations from their
production schedules?

C. Day-Ahead Market Participation and Reliability Commitments

1. Day-Ahead Market Participation
    26. The presence of a day-ahead market is a key characteristic of
most RTOs/ISOs. When resources are scheduled accurately in the day-
ahead market, subsequent out-of-market commitments are minimized and
market participants can manage their financial exposure more
effectively. However, VERs appear to participate in the day-ahead
market on a limited basis, choosing instead to self-schedule the
majority of their supply in the real-time energy markets (i.e., act as
a price taker). Because day-ahead schedules are financially binding,
there can be significant financial risk for VERs participating in the
day-ahead market and not being able to meet these obligations in the
real-time market. This may serve as a disincentive for VERs to
participate in the day-ahead market.
    27. In light of the increasing number of VERs, the Commission is
interested in receiving comments on whether the lack of day-ahead
market participation may be resulting in costly out-of-market
commitments, thereby rendering rates unjust and unreasonable, as well
as whether the financial risk associated with participating in the day-
ahead market may unduly discriminate against VERs by inhibiting their
ability to participate in such a market. Such comments should enable
the Commission to determine whether reforms are necessary to facilitate
VERs to participate more in the day ahead market rather than primarily
in the real time market.
    28. To that end, the Commission seeks comment on the following
questions:
    1. Does the lack of day-ahead market participation by VERs present
operational challenges or reduce market transparency as the number of
VERs increases? Will out-of-market commitments increase as the number
of VERs increases? If so, why?
    2. How can new or existing market design features assure that the
day-ahead market will accurately represent real-time system conditions
and that day-ahead and real-time energy prices will converge under the
scenario of increasing numbers of VERs?
    3. Do current RTO/ISO market designs place undue barriers to
participation in forward markets by VERs? Could the timing of certain
RTO/ISO market design elements, such as the day-ahead market, be
modified in a manner that would facilitate VERs to participate more in
the day ahead market rather than primarily in the real time market? If
so, how?
    4. Would the use of more accurate forecasting tools facilitate
participation of VERs in the day-ahead market rather than primarily in
the real time market? If so, how?

    5. Should the financial risk of VERs' participating in the day-
ahead market be different than the risk imposed on other resources in
that market in recognition of their unique characteristics? Are there
settlement practices, such as netting deviations, which could be
employed to address VERs' participating in the day-ahead market? If so,
what are they?
    6. Will changes to the financial risk of participating in the day-
ahead market encourage VERs to participate in day-ahead markets, and
will this participation result in day-ahead market schedules that
accurately reflect real-time market activity?
2. Reliability Commitments
    29. Following the results of the day-ahead market, RTOs/ISOs
conduct a reliability unit commitment process to ensure that sufficient
generation will be available in the appropriate places to meet the RTO/
ISO's estimate of the next day's forecasted demand. If the cleared
resources are insufficient to meet that demand, the RTO/ISO commits
additional units. Non-RTOs/ISOs conduct a similar assessment to
evaluate the sufficiency of bilaterally scheduled resources.
    30. Similar to the inefficiency associated with the lack of intra-
hour transmission scheduling, the lack of a more frequent unit
commitment process may result in unjust and unreasonable rates by
causing System Operators to make inefficient reliability commitment
decisions, which may cause unnecessary system uplift costs.
    31. To that end, the Commission seeks comment on the following
questions:
    1. Would the implementation of a formalized and transparent intra-
day reliability assessment and commitment process prior to each
operating hour reduce the amount of reserves needed and/or reduce
system uplift costs? What would be the optimal time (e.g., 4 to 6 hours
ahead of the operating hour) for such a process?
    2. Would an additional market that coincides with the timing of an
intra-day reliability commitment process be beneficial in the forward
scheduling of VERs? If such a market is implemented, would an intra-day
reliability commitment process be necessary? Should the frequency of
scheduling intervals resulting from such a market coincide with intra-
hour schedules discussed above?
    3. What role should centralized forecasting of VERs' output play in
reliability assessment and commitment processes?
D. Balancing Authority Coordination
    32. Smaller balancing authorities may be unable to capture the
benefits associated with VERs that are spread across a large and/or
diverse geographical area. Accordingly, the Commission is interested in
determining whether a limited ability of smaller balancing authorities
to efficiently integrate VERs may result in rates that are unjust and
unreasonable. Therefore, the Commission seeks to explore whether
increased coordination among balancing authorities has the potential to
enlarge the base of generation and demand available to customers,
thereby making variability more manageable and ultimately reducing
overall costs. In this proceeding, the Commission seeks comments on
ways to increase customer access to energy, capacity, and reserve
products through the use of pseudo-ties,\23\ dynamic scheduling, and/or
other tools and agreements.
---------------------------------------------------------------------------

    \23\ Pseudo-ties are defined as telemetered readings or values
that are used as ``virtual'' tie line flows between balancing
authorities where no physical tie line exists.
---------------------------------------------------------------------------

    33. To that end, the Commission seeks comment on the following
questions:
    1. Will smaller balancing authorities, when operated individually,
have higher VER integration costs than geographically or electrically
larger balancing authorities? If so, why?
    2. Should the Commission encourage the consolidation of balancing
authorities? If so, indicate the potential for and impediments to
consolidation among balancing authorities and the means by which the
Commission should encourage consolidation.
    3. What tools or arrangements (e.g., dynamic schedules, pseudo-
ties, and virtual balancing authorities) are available and/or could be
enhanced or created to reduce barriers to greater operational
coordination among balancing authorities? What role should the
Commission play in facilitating inter-balancing authority coordination?
    4. What are the costs and benefits, if any, associated with the
proliferation of small generation-only balancing authorities? How do
NERC Certification and Reliability Standards encourage or discourage
the creation of small generation-only balancing authorities?
    5. The Commission is interested in receiving comments on whether
the integration of VERs with small host balancing authorities may limit
the benefits derived from geographical diversity and increase
integration costs. Should the Commission encourage and/or facilitate
the creation of a VER balancing authority, essentially a large area
virtual balancing authority primarily designed to accommodate VERs
across a broad geographic region? What would be the benefits and costs
of creating such a large area entity?
    6. Would a large area VER balancing authority be capable of
capturing the reduced variability of VERs located across a broad and
geographically diverse region? What tariff or technical limitations
would prevent and/or inhibit the development of a large area VER
balancing authority?
    7. What reliability impacts may be associated with the creation of
a large area VER balancing authority?
    8. Should a large area VER balancing authority be limited only to
VERs? Why or why not?
    9. Should the Commission consider establishing specific policies
that support the creation of a large area VER balancing authority? If
so, why?

E. Reserve Products and Ancillary Services

    34. During normal operations, System Operators maintain reserve
products to ensure that demand and generation are kept in balance.\24\
Reserve products are generally defined by the timeframes in which they
are available. In the moments-to-seconds timeframe, Frequency Response
services provide an immediate arresting of the frequency decline or
increase due to any system imbalance. In the seconds-to-minutes
timeframe, regulation services provide maneuverable capacity (typically
through automatic generation control), and in the minutes-to-hours time
frame, following services \25\ allow for the rapid deployment of
resources to maintain and/or restore system balance.
---------------------------------------------------------------------------

    \24\ Contingency Reserves are used to recover from variations
caused by a system disturbance but not for balancing normal
variations.
    \25\ In RTO/ISO markets, following services are generally
provided through real-time energy markets.
---------------------------------------------------------------------------

    35. The Commission seeks to explore whether the variability
associated with increased VER deployment may result in an over-reliance
on expensive reserves, such as regulation reserves. The Commission
seeks to ensure that reserves are being used efficiently such that the
resulting rates are just, reasonable, and not unduly discriminatory.
The Commission is also interested in ensuring that requirements for
VERs to contribute to system reliability are not unduly discriminatory.
Finally, the Commission seeks to ensure that changes to the rules or
requirements do not hinder the

reliable operation of the grid under the reliability standards.\26\
---------------------------------------------------------------------------

    \26\ See 16 U.S.C. 824o(a)(3).
---------------------------------------------------------------------------

    36. To that end, the Commission seeks comment on the following
questions:
    1. To what extent do existing reserve products provide System
Operators with the most cost-effective means of maintaining reliability
during VER ramping events? To what extent would the other reforms
discussed herein, if implemented, mitigate the need for additional
reforms to existing reserve products without adversely impacting system
reliability?
    2. How could System Operators, managing the variability of VER
resources, more fully utilize forecasting information and knowledge
about existing system conditions to optimize reserve requirement
levels?
    3. Would a following or similar reserve product facilitate the
reduction of costs associated with ensuring that sufficient reserve
capacity is available to address the uncertainty and variability
associated with VERs? If so, what are the ideal characteristics of such
a product?
    4. Existing contingency reserve products were designed to be
utilized by System Operators to respond to disturbances (i.e.,
contingency events) due to a loss of supply and to assure system
reliability.\27\ Does or should the definition of a contingency event
include extreme VER ramping events? If so, would an additional level of
contingency reserves be needed to achieve the same level of system
reliability? In responding to this question, please include a proposed
definition of ``extreme ramping event.''
---------------------------------------------------------------------------

    \27\ Disturbance Control Performance, Standard No. BAL-002-0
(Apr. 1, 2005).
---------------------------------------------------------------------------

    5. Should a new category of reserves, that would be similar to
contingency reserves, be developed to maintain reliability during VER
ramping events in a cost effective manner? If so, what benefit would
such reserves provide to System Operators and customers?
    6. Could the expanded use of reserve-sharing programs between
balancing authorities contribute to lowering the costs associated with
integrating VERs? If so, how?
    7. Should the ancillary services provisions of the pro forma OATT
be revised or new provisions added to expressly address the added
reserve capacity necessitated by increased number of VERs? If so, how?
    8. Are there new sources and/or providers for reserve products
(such as inter-balancing authority pooling arrangements, demand
response aggregators and/or storage devices) that can be used to
maintain reliability and lower reserve costs during VER ramping events?
Based on experience, are there characteristics of these new sources of
reserves that would positively or negatively impact their ability to
match the reserve product needs presented by the variability of VERs?
    9. To what extent are VERs capable of providing reserve services?
Should VERs be expected to provide reserve services? What are the
tariff and technical barriers that may impede VERs from providing these
reserve products?
    10. To what extent should all resources, and VERs in particular, be
required to provide Frequency Response? How would such a requirement be
implemented?
    11. Should the Commission revisit the reactive power requirements
set forth in Order No. 661? \28\ What other requirements, if any,
should apply to VERs to ensure that all resources contribute to grid
reliability in a manner that is not unduly discriminatory?
---------------------------------------------------------------------------

    \28\ Order No. 661, FERC Stats. & Regs. ] 31,186 at P 50-51.
---------------------------------------------------------------------------

F. Capacity Markets

    37. The procurement of capacity services, either through resource
adequacy bilateral programs or centralized capacity markets, is
commonplace in RTO/ISO markets.\29\ Typically, VERs are eligible to
receive compensation for capacity services in most RTOs/ISOs. However,
due to their operating characteristics and the capacity rating rules,
which vary among RTOs/ISOs, VERs are eligible to offer only a portion
of their nameplate capacity. The price paid for capacity services
depends in part on the amount of available capacity. Additionally,
resources that participate in capacity markets typically are required
to offer capacity in the day-ahead market, which, as discussed above,
VERs often do not do.
---------------------------------------------------------------------------

    \29\ Centralized capacity markets exist in ISO New England,
Inc., New York Independent System Operator, Inc., and PJM
Interconnection LLC. California Independent System Operator Corp.
and Midwest Independent Transmission System Operator, Inc. rely
primarily on bilateral resource adequacy programs to procure
capacity services.
---------------------------------------------------------------------------

    38. The Commission questions whether existing rules governing
capacity markets may result in rates for capacity services that are not
just and reasonable. Moreover, to the extent existing rules limit the
ability of VERs to provide capacity services that they are capable of
providing, the Commission seeks to explore whether such rules may be
unduly discriminatory.
    39. To that end, the Commission seeks comment on the following
questions:
    1. Should the Commission examine whether capacity rating rules as
applied to VERs are unduly discriminatory and investigate whether
standard rules may be appropriate?
    2. Do obligations for capacity resources to offer into the day-
ahead market unfairly discriminate against VERs? If so, how?
    3. As more VERs choose to become capacity resources, will existing
processes for compensating capacity services adequately compensate all
generating resources that may be needed for reliability services? If
not, what reforms may be necessary? For instance, should the Commission
examine formation of forward ancillary services capacity markets?
    4. Should capacity markets incorporate a goal of ensuring
sufficient generation flexibility to accommodate ramping events in
addition to the goal of ensuring sufficient generation to meet peak
demand?

G. Real-Time Adjustments

    40. Redispatch and curtailment protocols vary depending on the
region of the country and scenario. The Commission is interested in
receiving comments on whether VERs may be curtailed too frequently in
response to transmission congestion, minimum generation events,\30\ and
ramping events, because of a lack of clarity in curtailment protocols.
Accordingly, the Commission seeks to explore whether redispatch and
curtailment practices and protocols, especially as they relate to VERs,
are transparent, non-discriminatory and efficient. The Commission also
seeks to determine whether redispatch and curtailment protocols may
result in unnecessary costs, thereby rendering rates unjust and
unreasonable.
---------------------------------------------------------------------------

    \30\ During a minimum generation event, system demand is at its
lowest and generation resources tend to operate at the minimum
feasible output level.
---------------------------------------------------------------------------

    41. To that end, the Commission seeks comment on the following
questions:
    1. How have redispatch and curtailment practices changed with
increased numbers of VERs? Are there any shortcomings of current
redispatch and curtailment practices?
    2. Do existing redispatch and curtailment processes unduly
discriminate against VERs? If so, how should they be modified?
    3. Some RTOs/ISOs will redispatch VERs based on required economic
bids. Should all RTOs/ISOs implement similar practices? Why or why not?

    4. Should transmission loading relief protocols be altered to allow
reliability coordinators in non-RTO/ISO regions to consider economic
merit when considering curtailing VERs? If so, how? Similarly, should
redispatch and curtailment protocols in non-RTOs/ISOs be revised to
consider economic merit for all resources? If so, how?
    5. Is the increasing number of VERs affecting operational issues
that arise during minimum generation events? Are there ways to minimize
curtailments during a minimum generation event? Should conventional
base-load resources be offered incentives to lower their minimum
operating levels or even shut down during minimum generation events to
reflect an economically efficient dispatch of resources? If so, what
would be the benefits and costs of doing so?
    6. To what extent do VERs have the capability to respond to
specific dispatch instructions? Are there any advanced technologies
that could be adopted by VERs to control output to match system needs
more effectively? Should incentives be put into place for VERs that can
respond to dispatch instructions? If so, what types of incentives would
be appropriate?

IV. Comment Procedures

    42. The Commission invites interested persons to submit comments,
and other information on the matters, issues and specific questions
identified in this notice.
    43. Comments are due March 29, 2010. Comments must refer to Docket
No. RM10-11-000, and must include the commenter's name, the
organization they represent, if applicable, and their address in their
comments.
    44. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's Web site at http://
www.ferc.gov. The Commission accepts most standard word processing
formats. Documents created electronically using word processing
software should be filed in native applications or print-to-PDF format
and not in a scanned format. Commenters filing electronically do not
need to make a paper filing.
    45. Commenters that are not able to file comments electronically
must send an original and 14 copies of their comments to: Federal
Energy Regulatory Commission, Secretary of the Commission, 888 First
Street, NE., Washington, DC 20426.
    46. All comments will be placed in the Commission's public files
and may be viewed, printed, or downloaded remotely as described in the
Document Availability section below. Commenters on this proposal are
not required to serve copies of their comments on other commenters.

V. Document Availability

    47. In addition to publishing the full text of this document in the
Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's
Public Reference Room during normal business hours (8:30 a.m. to 5 p.m.
Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.
    48. From FERC's Home Page on the Internet, this information is
available on eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number excluding the last three digits of this document in the docket
number field.
    49. User assistance is available for eLibrary and the FERC's Web
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or e-mail at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. E-mail the Public Reference Room at
<EMAIL_ADDRESS>
    By direction of the Commission. Commissioner Norris voting
present.
Kimberly D. Bose,
Secretary.
[FR Doc. 2010-1536 Filed 1-26-10; 8:45 am]
BILLING CODE 6717-01-P


[Federal Register Volume 87, Number 36 (Wednesday, February 23, 2022)]
[Notices]
[Pages 10193-10196]
[FR Doc No: 2022-03738]

=======================================================================
-----------------------------------------------------------------------

ENVIRONMENTAL PROTECTION AGENCY

[EPA-HQ-OW-2020-0426; FRL-8421-02-OW]

Proposed 2022 Clean Water Act Financial Capability Assessment
Guidance

AGENCY: Environmental Protection Agency (EPA).

ACTION: Notice; request for comment.

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

SUMMARY: When municipal discharges cause violations of the Clean Water
Act (CWA), EPA sets a schedule for the municipality to address them as
soon as possible. When developing schedules to implement the control
measures, EPA considers factors such as public health, environmental
protection, and a community's financial capability. The Proposed 2022
Financial Capability Assessment (FCA) Guidance describes the financial
information and formulas the Agency intends to use to assess the
financial resources a community has available to implement control
measures. The Proposed 2022 FCA directly incorporates relevant portions
of the 1997 Combined Sewer Overflows--Guidance for Financial Capability
Assessment and Schedule Development (1997 FCA Guidance) and EPA's 2014
Financial Capability Assessment Framework for Municipal Clean Water Act
Requirements (2014 FCA Framework) as Appendices. Once finalized, EPA
intends for the Proposed 2022 FCA to replace the 1997 FCA Guidance to
evaluate a community's capability to fund CWA control measures in both
the permitting and enforcement context. Additionally, EPA intends
Section IV.g of the 2022 FCA to assist states and authorized tribes in
the consideration of economic impacts to public entities for supporting
revisions to designated uses, water quality standard (WQS) variances,
and antidegradation reviews for high quality waters. The Proposed 2022
FCA reflects EPA's consideration of public comments received in
response to its September 18, 2020 Federal Register publication. The
contents of this guidance document do not have the force and effect of
law and are not meant to bind the public in any way. This document is
intended only to provide clarity to the public regarding existing
requirements under the law or agency policies.

DATES: Comments must be received on or before April 25, 2022.

ADDRESSES: You may send comments, identified by Docket ID No. EPA-HQ-
OW-2020-0426, by the following method:
     Federal eRulemaking portal: https://www.regulations.gov/.
Follow the online instructions for submitting comments.
    Instructions: All submissions received must include the Docket ID
No. for this guidance. Comments received may be posted without change
to https://www.regulations.gov/, including any personal information
provided. For detailed instructions on sending comments and additional
information on the guidance process, see the ``Request for Public
Comments'' heading of the SUPPLEMENTARY INFORMATION section of this
document. Out of an abundance of caution for members of the public and
our staff, the EPA Docket Center and Reading Room are open to the
public by appointment only to reduce the risk of transmitting COVID-19.
Our Docket Center staff also continues to provide remote customer
service via email, phone, and webform. Hand deliveries and couriers may
be received by scheduled appointment only. For further information on
EPA Docket Center services and the current status, please visit us
online at https://www.epa.gov/dockets.

FOR FURTHER INFORMATION CONTACT: Sonia Brubaker, Office of Wastewater
Management, Water Infrastructure Division (MC4204M), Environmental
Protection Agency, 1200 Pennsylvania Ave. NW, Washington, DC 20460;
telephone number:<PHONE_NUMBER>; email address:
[email protected].

SUPPLEMENTARY INFORMATION:
I. Purpose of the Proposed 2022 Financial Capability Assessment
Guidance
II. Changes From the September 2020 Proposed FCA Guidance
III. Overview of the Proposed 2022 FCA Guidance
IV. Request for Public Comments

EPA'S Proposed 2022 Financial Capability Assessment Guidance

I. Purpose of the Proposed 2022 Financial Capability Assessment
Guidance

    The Proposed 2022 FCA advances the ability of communities to more
thoroughly demonstrate the financial impacts they face and increases
the transparency of EPA's considerations as it endeavors to
consistently apply FCA methodologies across the country. The Proposed
2022 FCA allows communities to submit more consistent and comprehensive
information relevant to the entire community's capability to fund CWA
control measures and programs. Specifically, the Proposed 2022 FCA
includes templates and calculations that communities can use to submit
information regarding lowest quintile income (LQI), drinking water
costs, financial models or studies, and other relevant information. The
templates and calculations include references to publicly available
data sources that can be used in compiling this information.
    The Proposed 2022 FCA sets forth two alternative approaches for
assessing a community's financial capability to carry out CWA control
measures. The first alternative is the existing 1997 FCA methodology
with expanded consideration of lowest quintile income and poverty in
the service area. The second alternative is the development of a
dynamic financial and rate model that looks at the impacts of rate
increases over time on utility customers. Additionally, EPA recommends
the application of the methodologies from Alternative 1 of the Proposed
2022 FCA to the consideration of economic impacts to public entities
when making decisions on WQS variances and antidegradation reviews. In
appropriate cases, these methodologies also inform decisions about
revisions to designated uses, subject to additional analyses.
    EPA is proposing to base its FCA metrics on data that is available
in the American Community Survey (ACS). The ACS is conducted every year
by the U.S. Census Bureau to provide up-to-date information about the
social and economic conditions of communities. The annual updates
include key socio-demographic information at an appropriate geographic
scale with historic continuity. The ACS can produce data showing the
quintiles of household income (each quintile defines the household
income range for 20% of a community's households). The 2022 Proposed
FCA metrics meet the following criteria recommended by the National
Academy of Public Administration (NAPA): \1\
---------------------------------------------------------------------------

    \1\ NAPA issued a report titled ``Developing a New Framework for
Community Affordability of Clean Water Services'' in October 2017.
---------------------------------------------------------------------------

     Readily available from publicly available data sources;
     Clearly defined and understood;
     Simple, direct, and consistent;
     Valid and reliable measures, according to conventional
research standards; and
     Applicable for comparative analyses among permittees.
    The 2022 Proposed FCA strengthens both CWA protections and water
service affordability protections. For the first time, EPA may ask
municipalities negotiating compliance schedules and certain WQS
revisions to affirmatively demonstrate actions to reduce or mitigate
the financial impact of water service costs on the lowest quintile
households and to achieve compliance as expeditiously as possible.

II. Changes From the September 2020 Proposed FCA Guidance

    On September 18, 2020, EPA published a Proposed 2020 Financial
Capability Assessment for Clean Water Act Obligations (Proposed 2020
FCA) in the Federal Register for notice and public comment.\2\ On
January 12, 2021, EPA posted a pre-publication version of the FCA
Guidance on the Agency's website. The pre-publication FCA was never
published in the Federal Register and was withdrawn for review and
approval in accordance with the January 20, 2021 White House
Memorandum, Regulatory Freeze Pending Review.\3\ The Proposed 2022 FCA
reflects EPA's consideration of public comments received in response to
its September 2020 Federal Register publication, as well as feedback
received through various stakeholder outreach sessions since then. The
three major changes from the Proposed 2020 FCA are outlined below.
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    \2\ See 85 FR 58352 (September 18, 2020).
    \3\ See https://www.whitehouse.gov/briefing-room/presidential-actions/2021/01/20/regulatory-freeze-pending-review/.
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1. Consideration of Lowest Quintile Households and Poverty Indicators

    EPA originally proposed to add two new FCA metrics, the Lowest
Quintile Residential Indicator (LQRI) and the Poverty Indicator (PI).
The LQRI was intended to evaluate the financial impact of CWA costs on
lowest quintile households in a community by calculating the ratio of
adjusted costs per lowest quintile household to the service area's
lowest quintile income.
    While commenters were supportive of the new poverty measures, many
expressed concerns about the methodology proposed to scale the costs
for lowest quintile households and the proposed LQRI thresholds. A
number of community-specific factors--such as age of infrastructure,
housing type, and efficiency of water appliances--may impact water
usage and costs to lowest quintile households. In addition, if the
community charges residential customers on a fixed rate structure,
i.e., low-volume households receive the same bill as high-volume
households, a metric that scales down estimates of cost based on
projected water use would not be appropriate.
    EPA recognizes that considering lowest quintile income is an
important measure to supplement existing FCA metrics. Median household
income (MHI) does not account for the variability of income
distribution from community to community. Even when communities have a
similar MHI, infrastructure investments could have a greater financial
impact on low-income households in certain situations, such as when
there is a wide distribution between the highest and lowest income
customers. For this reason, EPA is proposing two simplified Proposed
Options to assess the severity and prevalence of poverty in a
community's service area. EPA is seeking comment on both Proposed
Options, but only one of the Proposed Options is to be included in the
final 2022 FCA Guidance. Both Options consider the community's lowest
quintile income as benchmarked against the national lowest quintile
income, as well as five poverty indicators:
     Percentage of Population with Income Below 200% of Federal
Poverty Level;
     Percentage of Population Receiving Food Stamps/SNAP
Benefits;
     Percentage of Vacant Households;
     Trend in Household Growth; and
     Percentage of Unemployed Population 16 and Over in
Civilian Labor Force.
    EPA has determined that the methodology of either Option 1 or 2
would enable EPA to distinguish between two communities with similar
MHI but different levels of poverty.
    Proposed Option 1 for Comment: This Option would add a single new
metric to the assessment, the Lowest Quintile Poverty Indicator (LQPI)
to be considered with the Residential Indicator and Financial
Capability Indicator. The LQPI would combine a lowest quintile income
element with poverty indicator elements. To ensure that both the
severity and prevalence of

poverty are reflected in the LQPI metric, EPA would give equal weight
to the LQI (50%) and the five prevalence of poverty indicators
(weighted at 10% each for a total of 50%).
    Under Proposed Option 1, Residential Indicator and Financial
Capability Indicator would be combined in a matrix to determine an FCA
Score. An Initial LQPI Score would be calculated, and adjusted based on
a Financial Alternatives Analysis, if appropriate. Finally, the FCA
Score and Final LQPI Score would be combined in the Expanded FCA Matrix
to provide the final FCA result.
    Proposed Option 2 for Comment: This Option would add two new
metrics, the Lowest Quintile Income Indicator (LQII) and the Poverty
Indicator (PI) to be considered with the Residential Indicator and
Financial Capability Indicator. The LQII is the lowest quintile income
metric, and the PI is a separate metric based on the average score of
the five prevalence of poverty indicators.
    Under Proposed Option 2, the Residential Indicator and Financial
Capability Indicator would be combined in a matrix to determine an FCA
Score. Then, LQII and PI would be each calculated separately. The LQII
and PI would be combined in a matrix to determine an Initial LQPI
Score. The Initial LQPI Score would be adjusted based on a Financial
Alternatives Analysis, if appropriate. Finally, the FCA Score and Final
LQPI Score would be combined in the Expanded FCA Matrix to provide the
final FCA result.

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

------------------------------------------------------------------------
   Summary of Section IV.b of the Proposed 2022 FCA: Step 3 Shows Two
Proposed Options for Consideration of Lowest Quintile Income and Poverty
                               Indicators
------------------------------------------------------------------------
Step 1: Calculate Residential Indicator.
Step 2: Calculate Financial Capability Indicator.
Step 3: Calculate Initial Lowest Quintile Poverty Indicator Score--Two
 Proposed Options.
------------------------------------------------------------------------

Step 3 Under Proposed Option 1              Step 3 Under Proposed Option
                                             2

Calculate Initial Lowest Quintile Poverty   First, calculate the Lowest
 Indicator Score based on the six elements   Quintile Income Indicator
 below:                                      Score (i.e., community's
 Lowest Quintile Income              Lowest Quintile Income
 benchmarked to National LQI--50% of         benchmarked to the National
 score.                                      LQI).
 Percentage of Unemployed           Then, average the five
 Population 16 and Over in Civilian Labor    poverty elements below to
 Force--10% of score.                        determine the Poverty
 Percentage of Population Living     Indicator Score:
 Under 200% of Poverty Level--10% of         Percentage of
 score.                                      Unemployed Population 16
 Percentage of Population            and Over in Civilian Labor
 Receiving Food Stamps/SNAP Benefits--10%    Force.
 of score.                                   Percentage of
 Percentage of Vacant Households--   Population Living Under
 10% of score.                               200% of Poverty Level.
 Trend in Household Growth--10% of   Percentage of
 score.                                      Population Receiving Food
                                             Stamps/SNAP Benefits.
                                             Percentage of
                                             Vacant Households.
                                             Trend in Household
                                             Growth.
                                            Finally, combine the LQI and
                                             PI in the Initial LQPI
                                             Matrix to determine the
                                             Initial LQPI Score.
------------------------------------------------------------------------
Step 4: Perform Financial Alternatives Analysis if Initial LQPI Score is
 ``medium'' impact or ``high'' impact.
Step 5: Determine Final LQPI Score.
Step 6: First, combine RI and FCI to determine Financial Capability
 Matrix Score. Then, combine Financial Capability Matrix Score and Final
 LQPI Score to determine Expanded Financial Capability Assessment Matrix
 Score.
------------------------------------------------------------------------

2. Addition of Financial Alternatives Analysis

    Where CWA compliance costs may have an impact on a community's
residents with incomes in the lowest quintile, a longer schedule may
not always be the best solution to address impacts to those residents.
In particular, if a community shows strong economic indicators in other
categories, there may be better options for the community to address
the potential financial burden faced by its lowest quintile
residents.\4\ If the intended goal is to help a community's lowest
income residents, an extended CWA schedule may in fact have the
opposite effect if it delays addressing pollution in the neighborhoods
where they live.
---------------------------------------------------------------------------

    \4\ The CSO Policy identifies three additional financial
considerations for negotiating implementation schedules: Grant and
loan availability; previous and current residential, commercial and
industrial sewer user fees and rate structures; and other viable
funding mechanisms and sources of financing. See 59 FR 18688, 18694
(April 19, 1994).
---------------------------------------------------------------------------

    Use of variable rate structures, customer assistance programs, and
applications for grants or subsidies from the Clean Water State
Revolving Fund (CWSRF) are all potential tools to enable shorter
compliance schedules by allowing increased total spending on compliance
without burdening low-income customers. Federal funding initiatives and
programs such as the Bipartisan Infrastructure Law (BIL), American
Rescue Plan Act (ARPA), State Revolving Loan Funds (SRFs), Water
Infrastructure Finance and Innovation Act (WIFIA) and others provide
billions of dollars for state, local, territorial, and tribal
governments. For instance, the Bipartisan Infrastructure Law has
provided $11.7 billion in additional funds to the CWSRF. The state
match requirement has been reduced to 10% for the first two years and
49% of the money will be provided as grants or principal forgiveness
loans to communities. These resources create a historic opportunity for
communities to address long-standing challenges. In addition, shorter
compliance schedules provide water quality and public health
improvements that deliver important social, environmental, and economic
benefits to the community. For these reasons, EPA does not intend to
provide extended CWA compliance schedules or greater consideration for
WQS decisions unless the community demonstrates that it has taken all
feasible steps to reduce or mitigate the financial impact of water
service costs on the lowest quintile households and to achieve
compliance as expeditiously as possible. In evaluating this
demonstration, EPA expects to look comprehensively at the community's
financial strategy, including, but not limited to, an analysis of the
community's approach to covering costs through rate structure and
design as well as its other initiatives to assist low-income customers
while assuring necessary and timely compliance with environmental
requirements.

3. Modification of Scheduling Benchmarks

    The Proposed 2020 FCA provided that communities with ``medium'' FCA
impacts could qualify for compliance schedules of up to 15 years and
``high'' impact communities could receive compliance schedules up to 25
years, or as long as the useful life of the CSO controls for unusually
high impacts. For users of the Proposed 2022 FCA, it is more
transparent and consistent to define a recommended scheduling boundary
rather than retain the ``useful life'' language. It is important to
consider human health and environmental impacts as well as cost when
considering extended schedules. EPA is also mindful that prolonging
water quality impairments could exacerbate environmental justice
concerns. EPA believes that, for unusually high impacts, 25 years is a
reasonable recommended scheduling benchmark that is more consistent
with environmental protection and the Agency's past FCA practice.
    EPA proposes to revise the FCA guidance to keep 15 years as the
outer recommended boundary for ``medium'' impact communities and change
the benchmark for ``high'' impact communities to 20 years, or up to 25
years for unusually high impacts, but is seeking comment on whether
these are appropriate recommended scheduling boundaries.

III. Overview of the Proposed 2022 FCA Guidance

    The 2022 FCA Guidance recommends two alternative approaches for
assessing a community's financial capability to carry out CWA control
measures. The first alternative is the existing 1997 FCA methodology
with expanded consideration of poverty and impacts on the population in
the service area with incomes in the lowest quintile. EPA is retaining
the 1997 Residential Indicator (i.e., 2% of MHI) and the Financial
Capability Indicator because they measure factors required under the
Clean Water Act by the CSO Policy as part of a financial capability
assessment.\5\ These indicators also allow for consistent comparative
analysis among communities. The new critical metric, the Lowest
Quintile Poverty Indicator (LQPI), allows the Agency to assess severity
and prevalence of poverty. The second alternative is the development of
a dynamic financial and rate model that looks at the impacts of rate
increases over time on utility customers.
---------------------------------------------------------------------------

    \5\ The Clean Water Act requires that each permit, order, or
decree for a discharge from a municipal combined storm and sanitary
sewer conform to the CSO Policy. 33 U.S.C. 1342(q). The CSO Policy
lists the following considerations for financial capability: Median
household income; total annual wastewater and CSO control costs per
household as a percent of median household income; overall net debt
as a percent of full market property value; property tax revenues as
a percent of full market property value; property tax collection
rate; unemployment; and bond rating. See 59 FR 18688, 18694 (April
19, 1994).
---------------------------------------------------------------------------

    Both alternatives permit consideration of other metrics and may
support an extended implementation schedule. Nonetheless, EPA does not
anticipate establishing implementation schedules that would exceed 20
years, or up to 25 years for communities that demonstrate unusually
high impacts. The Proposed 2022 FCA can help to ensure that local
challenges related to low-income households are better reflected in CWA
implementation schedules. Consistent with previous policy, EPA plans to
consider any relevant financial or demographic information presented
that illustrates the unique or atypical circumstances faced by a
community. The Proposed 2022 FCA is available at: https://www.regulations.gov/, Docket ID No. EPA-HQ-OW-2020-0426.
    Additionally, EPA recommends application of the methodologies from
the Proposed 2022 FCA to the consideration of economic impacts to
public entities for supporting revisions to designated uses, WQS
variances, and antidegradation reviews for WQS. EPA intends that the
recommended expanded matrix for WQS decisions in the Proposed 2022 FCA,
once finalized, along with the electronic spreadsheet tools for the
public sector,\6\ would replace the worksheets and calculations for the
public sector sections of the 1995 Interim Economic Guidance for Water
Quality Standards. The Proposed 2022 FCA does not revise the
recommended methodology in the private sector sections of the 1995 WQS
Guidance.
---------------------------------------------------------------------------

    \6\ These electronic spreadsheet tools for the public sector,
available at https://www.epa.gov/wqs-tech/spreadsheet-tools-evaluate-economic-impacts-public-sector, encompass the data inputs
and calculations of the 1995 Interim Economic Guidance for Water
Quality Standards.
---------------------------------------------------------------------------

IV. Request for Public Comments

    EPA requests public comment on the Proposed 2022 FCA. Specifically,
EPA is requesting comment on the following:

    1. Should the Final 2022 FCA incorporate a single new metric--
LQPI--that considers lowest quintile income and poverty elements
together? Or should the Final 2022 FCA incorporate two new metrics
(a lowest quintile income indicator and a poverty indicator) to be
calculated separately and combined in a matrix?
    2. EPA is seeking additional examples or case studies of funding
and financing considerations to add to Appendix C.
    3. EPA is seeking feedback on the current proposed scheduling
benchmarks of 20 years for ``high'' Expanded FCA Matrix impacts, or
25 years for unusually high impacts. If commentors propose different
benchmarks, EPA is requesting examples to support the basis for such
benchmarks.

    Dated: February 10, 2022.
Andrew D. Sawyers,
Director, Office of Wastewater Management, Office of Water.
[FR Doc. 2022-03738 Filed 2-22-22; 8:45 am]
BILLING CODE 6560-50-P


[Federal Register Volume 83, Number 203 (Friday, October 19, 2018)]
[Notices]
[Pages 53070-53071]
[FR Doc No: 2018-22813]

=======================================================================
-----------------------------------------------------------------------

DEPARTMENT OF HOMELAND SECURITY

Coast Guard

[Docket No. USCG-2018-0877]

National Maritime Security Advisory Committee; Meeting

AGENCY: U.S. Coast Guard, Department of Homeland Security.

ACTION: Notice of Federal Advisory Committee meeting.

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

SUMMARY: The National Maritime Security Advisory Committee will meet in
Houston, Texas, to review and discuss various issues relating to
national maritime security. All meetings will be open to the public.

DATES:
    Meetings. The Committee will meet on Tuesday, November 6, 2018,
from 12:00 noon to 5 p.m. and on Wednesday, November 7, 2018, from 8
a.m. to 1 p.m. These meetings may close early if all business is
finished.
    Comments and supporting documentation. To ensure your comments are
reviewed by Committee members before the meetings, submit your written
comments no later than November 1, 2018.

ADDRESSES: The meeting will be held at the Double Tree Hilton Hotel by
Houston Hobby Airport, 8181 Airport Boulevard, Houston, TX 77061,
HoustonHobbyAirport.DoubleTree.com.
    This meeting will be broadcast via a web enabled interactive online
format and teleconference line. To participate via teleconference,
contact the individual listed in the FOR FURTHER INFORMATION CONTACT
section no later than November 1, 2018. Additionally, if you would like
to participate in this meeting via the online web format, please log
onto https://share.dhs.gov/nmsac/ and follow the online instructions to
register for this meeting. If you encounter technical difficulties,
contact Mr. Ryan Owens at<PHONE_NUMBER>.
    For information on facilities or services for individuals with
disabilities, or to request special assistance at the meetings, contact
the individual listed in FOR FURTHER INFORMATION CONTACT below as soon
as possible.
    Written comments must be submitted using the Federal eRulemaking
Portal: http://www.regulations.gov. If you encounter technical
difficulties, contact the individual in the FOR FURTHER INFORMATION
CONTACT section of this document.
    Instructions: You are free to submit comments at any time,
including orally at the meetings, but if you want Committee members to
review your comment before the meetings, please submit your comments no
later than November 1, 2018. We are particularly interested in comments
on the issues in the ``Agenda'' section below. You must include
``Department of Homeland Security'' and the docket number [USCG-2018-
0877]. Comments received will be posted without alteration at http://www.regulations.gov including any personal information provided. For
more information about privacy and the docket, review the Privacy and
Security Notice for the Federal Docket Management System at https://regulations.gov/privacyNotice.
    Docket Search: For access to the docket or to read documents or
comments related to this notice, go to http://www.regulations.gov, and
use docket number ``USCG-2018-0877'' in the ``Search'' box, press
Enter, and then click on the item you wish to view.

FOR FURTHER INFORMATION CONTACT: Mr. Ryan Owens, Alternate Designated
Federal Officer of the National Maritime Security Advisory Committee,
2703 Martin Luther King Jr. Avenue SE, Washington, DC 20593, Stop 7581,
Washington, DC 20593-7581; telephone<PHONE_NUMBER> or email
[email protected].

SUPPLEMENTARY INFORMATION: Notice of this meeting is in compliance with
the Federal Advisory Committee Act, Title 5, United States Code,
Appendix. The National Maritime Security Advisory Committee operates
under the authority of 46 U.S.C. 70112.
    The National Maritime Security Advisory Committee provides advice,
consults with, and makes recommendations to the Secretary of Homeland
Security, via the Commandant of the Coast Guard, on matters relating to
national maritime security.

Agenda

Day 1

    The Committee will meet to review, discuss and formulate
recommendations on the following issues:
    (1) Cyber Security Update. Members will receive an update from the
U.S. Coast Guard concerning the draft Cyber Security Navigation and
Vessel Inspection Circular and other Cyber Security matters related to
the Marine Transportation System.
    (2) Unmanned Aircraft Systems. The Committee will receive an update
from the U.S. Coast Guard concerning the threat of Unmanned Aircraft
Systems and the efforts of the U.S. Coast Guard to provide guidance to
the maritime industry in addressing the concern these aircraft pose to
critical infrastructure.
    (3) Port of Houston Maritime Security Review. The Committee will
receive a brief on the current state of maritime security at the Port
of Houston.
    (4) Public Comment period.

Day 2

    The Committee will meet to review, discuss and formulate
recommendations on the following issues:
    (1) Member Report. The Committee members will each provide an
update on the security developments in each of the respective member's
representative segment.
    (2) Customs-Trade Partnership Against Terrorism. The Committee will
receive an update on efforts of from Customs and Border Protection to
revise the security requirements of the program.

    (3) American Association of Ports Authority Port Security Grant
Survey. The Committee will receive a brief on the results of the
Survey, conducted over the past year.
    (4) Public comment period.
    Public comments or questions will be taken throughout the meeting
as the Committee discusses the issues and prior to deliberations and
voting. There will also be a public comment period at the end of each
meeting.
    Speakers are requested to limit their comments to 5 minutes. Please
note that the public comment period may end before the period allotted,
following the last call for comments. Contact the individual listed in
the FOR FURTHER INFORMATION CONTACT section above to register as a
speaker.
    A copy of all meeting documentation will be available at https://homeport.uscg.mil/missions/maritime-security/national-maritime-security-advisory-committee-(nmsac)/full-committee-meeting-minutes by
November 2, 2018.

    Dated: October 12, 2018.
Jennifer F. Williams,
Captain, U.S. Coast Guard, Director of Inspections and Compliance.
[FR Doc. 2018-22813 Filed 10-18-18; 8:45 am]
 BILLING CODE 9110-04-P