[Federal Register Volume 87, Number 164 (Thursday, August 25, 2022)]
[Notices]
[Pages 52379-52381]
[FR Doc No: 2022-18335]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. CP22-486-000]

Texas Eastern Transmission, LP; Notice of Intent To Prepare an
Environmental Impact Statement for the Proposed Appalachia to Market II
and Entriken HP Replacement Project and Request for Comments on
Environmental Issues, and Schedule for Environmental Review

    The staff of the Federal Energy Regulatory Commission (FERC or
Commission) will prepare an environmental impact statement (EIS) that
will discuss the environmental impacts of the Appalachia to Market II
and Entriken HP Replacement Project (Project) involving construction
and operation of facilities by Texas Eastern Transmission, LP (Texas
Eastern) in Lebanon, Indiana, and Huntingdon counties, Pennsylvania.
The Commission will use this EIS in its decision-making process to
determine whether the Project is in the public convenience and
necessity. The schedule for preparation of the EIS is discussed in the
Schedule for Environmental Review section of this notice.
    This notice announces the opening of the scoping process the
Commission will use to gather input from the public and interested
agencies regarding the project. As part of the National Environmental
Policy Act (NEPA) review process, the Commission takes into account
concerns the public may have about proposals and the environmental
impacts that could result from its action whenever it considers the
issuance of a Certificate of Public Convenience and Necessity. This
gathering of public input is referred to as ``scoping.'' The main goal
of the scoping process is to focus the analysis in the environmental
document on the important environmental issues. Additional information
about the Commission's NEPA process is described below in the NEPA
Process and the EIS section of this notice.
    By this notice, the Commission requests public comments on the
scope of issues to address in the environmental document, including
comments on potential alternatives and impacts, and any relevant
information, studies, or analyses of any kind concerning impacts
affecting the quality of the human environment. To ensure that your
comments are timely and properly recorded, please submit your comments
so that the Commission receives them in Washington, DC on or before
5:00 p.m. Eastern Time on September 19, 2022. Comments may be submitted
in written or oral form. Further details on how to submit comments are
provided in the Public Participation section of this notice.
    If you are a landowner receiving this notice, a pipeline company
representative may contact you about the acquisition of an easement to
construct, operate, and maintain the proposed facilities. The company
would seek to negotiate a mutually acceptable easement agreement. You
are not required to enter into an agreement. However, if the Commission
approves the Project, the Natural Gas Act conveys the right of eminent
domain to the company. Therefore, if you and the company do not reach
an easement agreement, the pipeline company could initiate condemnation
proceedings in court. In such instances, compensation would be
determined by a judge in accordance with state law. The Commission does
not grant, exercise, or oversee the exercise of eminent domain
authority. The courts have exclusive authority to handle eminent domain
cases; the Commission has no jurisdiction over these matters.
    Texas Eastern provided landowners with a fact sheet prepared by the
FERC entitled ``An Interstate Natural Gas Facility On My Land? What Do
I Need To Know?'' which addresses typically asked questions, including
the use of eminent domain and how to participate in the Commission's
proceedings. This fact sheet along with other landowner topics of
interest are available for viewing on the FERC website (www.ferc.gov)
under the Natural Gas Questions or Landowner Topics link.

Public Participation

    There are three methods you can use to submit your comments to the
Commission. The Commission encourages electronic filing of comments and
has staff available to assist you at<PHONE_NUMBER> or
[email protected]. Please carefully follow these instructions
so that your comments are properly recorded.
    (1) You can file your comments electronically using the eComment
feature, which is located on the Commission's website (www.ferc.gov)
under the link to FERC Online. Using eComment is an easy method for
submitting brief, text-only comments on a project;
    (2) You can file your comments electronically by using the eFiling
feature, which is located on the Commission's website (www.ferc.gov)
under the link to FERC Online. With eFiling, you can provide comments
in a variety of formats by attaching them as a file with your
submission. New eFiling users must first create an account by clicking
on ``eRegister.'' You will be asked to select the type of filing you
are making; a comment on a particular project is considered a ``Comment
on a Filing''; or
    (3) You can file a paper copy of your comments by mailing them to
the Commission. Be sure to reference the project docket number (CP22-
486-000) on your letter. Submissions sent via the U.S. Postal Service
must be addressed to: Kimberly D. Bose, Secretary, Federal Energy
Regulatory Commission, 888 First Street NE, Room 1A, Washington, DC
20426. Submissions sent via any other carrier must be addressed to:
Kimberly D. Bose, Secretary, Federal Energy Regulatory Commission,
12225 Wilkins Avenue, Rockville, Maryland 20852.
    Additionally, the Commission offers a free service called
eSubscription. This service provides automatic notification of filings
made to subscribed dockets, document summaries, and direct links to the
documents. Go to https://www.ferc.gov/ferc-online/overview to register
for eSubscription.

Summary of the Proposed Project, the Project Purpose and Need, and
Expected Impacts

    Texas Eastern proposes to abandon certain facilities and to
construct, install, own, operate, and maintain facilities in Lebanon,
Indiana, and Huntingdon counties in Pennsylvania. According to Texas
Eastern, the Project is designed to improve reliability on the Texas
Eastern system by replacing an

older gas-driven compressor unit with an electric-motor driven (EMD)
compressor unit at each of two compressor stations. The Project is
designed to provide up to 55,000 dekatherms per day of additional firm
natural gas transportation service from the Appalachia supply basin in
Southwest Pennsylvania to existing local distribution company customers
in New Jersey.
    The general location of the Project facilities is shown in appendix
1.\1\
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    \1\ The appendices referenced in this notice will not appear in
the Federal Register. Copies of the appendices were sent to all
those receiving this notice in the mail and are available at
www.ferc.gov using the link called ``eLibrary''. For instructions on
connecting to eLibrary, refer to the last page of this notice. At
this time, the Commission has suspended access to the Commission's
Public Reference Room due to the proclamation declaring a National
Emergency concerning the Novel Coronavirus Disease (COVID-19),
issued by the President on March 13, 2020. For assistance, contact
FERC at [email protected] or call toll free,<PHONE_NUMBER>
or TTY<PHONE_NUMBER>.
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    The Project would consist of the following facilities:
     the Line 28 Loop in Lebanon County, Pennsylvania, which
includes installation of approximately 2 miles of 36-inch-diameter
looping pipeline beginning at the terminus of Texas Eastern's existing
Line 28;
     a new receiver, valve, and crossover site at the end of
the Line 28 Loop to replace the existing receiver at the end of the
existing Line 28;
     the Armagh Compressor Station Modifications in Indiana
County, Pennsylvania, which includes installation of a 27,000
horsepower EMD compressor unit to replace an existing 22,000 hp gas-
driven turbine compressor unit, construction of a new electric
substation to provide power to the EMD compressor, and associated
facilities; and
     the Entriken Compressor Station Modifications in
Huntingdon County, Pennsylvania, which includes the installation of a
24,000 hp EMD compressor unit to replace an existing 22,000 hp gas-
driven turbine compressor unit, construction of a new electric
substation to provide power to the EMD compressor, and associated
facilities.
    Based on the environmental information provided by Texas Eastern,
construction of the proposed facilities would disturb about 155 acres
of land for the aboveground facilities and the pipeline. Following
construction, Texas would maintain about 79.0 acres for operation of
the Project facilities, and the remaining acreage would be restored and
revert to former uses. The Line 28 Loop would be installed adjacent to
Texas Eastern's existing lines within and adjacent to Texas Eastern's
existing right-of-way. The Armagh and Entriken Compressor Station
Modifications would occur fully within the parcels owned by Texas
Eastern, primarily within the fence line of existing facilities.
    Based on an initial review of Texas Eastern's proposal, Commission
staff have identified several expected impacts that deserve attention
in the EIS, including visual impacts, greenhouse gas emissions, and
potential impacts on special status species, environmental justice
communities, and air quality.

The NEPA Process and the EIS

    The EIS issued by the Commission will discuss impacts that could
occur as a result of the construction and operation of the proposed
Project under the relevant general resource areas:
     geology and soils;
     water resources and wetlands;
     vegetation and wildlife;
     threatened and endangered species;
     cultural resources;
     land use;
     socioeconomics and environmental justice;
     air quality and noise; and
     reliability and safety.
    Commission staff will also make recommendations on how to lessen or
avoid impacts on the various resource areas. Your comments will help
Commission staff focus its analysis on the issues that may have a
significant effect on the human environment.
    Staff will prepare a draft EIS which will be issued for public
comment. Commission staff will consider all timely comments received
during the comment period on the draft EIS and revise the document, as
necessary, before issuing a final EIS. Any draft and final EIS will be
available in electronic format in the public record through eLibrary
\2\ and the Commission's natural gas environmental documents web page
(https://www.ferc.gov/industries-data/natural-gas/environment/environmental-documents). If eSubscribed, you will receive instant
email notification when the environmental document is issued.
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    \2\ For instructions on connecting to eLibrary, refer to the
last page of this notice.
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Alternatives Under Consideration

    The EIS will evaluate reasonable alternatives that are technically
and economically feasible and meet the purpose and need for the
proposed action. Alternatives currently under consideration include:
     the no-action alternative, meaning the Project is not
implemented; and
     a system alternative evaluating whether the Project
purpose could be met by use of an existing pipeline system.
    With this notice, the Commission requests specific comments
regarding any additional potential alternatives to the proposed action
or segments of the proposed action. Please focus your comments on
reasonable alternatives (including alternative facility sites and
pipeline routes) that meet the Project objectives, are technically and
economically feasible, and avoid or lessen environmental impact.

Consultation Under Section 106 of the National Historic Preservation
Act

    In accordance with the Advisory Council on Historic Preservation's
implementing regulations for section 106 of the National Historic
Preservation Act, the Commission is using this notice to initiate
consultation with the applicable State Historic Preservation Office(s),
and other government agencies, interested Indian tribes, and the public
to solicit their views and concerns regarding the Project's potential
effects on historic properties.\3\ The Project EIS will document
findings on the impacts on historic properties and summarize the status
of consultations under section 106.
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    \3\ The Advisory Council on Historic Preservation's regulations
are at Title 36, Code of Federal Regulations, Part 800. Those
regulations define historic properties as any prehistoric or
historic district, site, building, structure, or object included in
or eligible for inclusion in the National Register of Historic
Places.
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Schedule for Environmental Review

    On July 19, 2022, the Commission issued its Notice of Application
for the Project. Among other things, that notice alerted other agencies
issuing federal authorizations of the requirement to complete all
necessary reviews and to reach a final decision on the request for a
federal authorization within 90 days of the date of issuance of the
Commission staff's final EIS for the Project. This notice identifies
the Commission staff's planned schedule for completion of the final EIS
for the Project, which is based on an issuance of the draft EIS in
February 2023.

Issuance of Notice of Availability of the final EIS--July 14, 2023
90-day Federal Authorization Decision Deadline \4\--October 12, 2023
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    \4\ The Commission's deadline applies to the decisions of other
federal agencies, and state agencies acting under federally
delegated authority, that are responsible for federal
authorizations, permits, and other approvals necessary for proposed
projects under the Natural Gas Act. Per 18 CFR 157.22(a), the
Commission's deadline for other agency's decisions applies unless a
schedule is otherwise established by federal law.

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    If a schedule change becomes necessary for the final EIS, an
additional notice will be provided so that the relevant agencies are
kept informed of the Project's progress.

Permits and Authorizations

    The table below lists the anticipated permits and authorizations
for the Project required under federal law. This list may not be all-
inclusive and does not preclude any permit or authorization if it is
not listed here. Agencies with jurisdiction by law and/or special
expertise may formally cooperate in the preparation of the Commission's
EIS and may adopt the EIS to satisfy its NEPA responsibilities related
to this Project. Agencies that would like to request cooperating agency
status should follow the instructions for filing comments provided
under the Public Participation section of this notice.

           Environmental Permits, Approvals, and Consultations
------------------------------------------------------------------------
                 Agency                    Permit or clearance required
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Federal Energy Regulatory Commission...  Certificate of Public
                                          Convenience and Necessity
                                          under Section 7(c) of the
                                          Natural Gas Act.
U.S. Army Corps of Engineers (USACE),    Clean Water Act Section 404,
 Baltimore and Pittsburgh District(s).    Pennsylvania State
                                          Programmatic General Permit.
Pennsylvania Department of               Clean Water Act Section 401,
 Environmental Protection (PADEP)         Water Quality Certification.
 Regional Permit Coordination Office.
U.S. Department of Interior, Fish and    Section 7 Endangered Species
 Wildlife Service (USFWS), Pennsylvania   Act Consultation; Migratory
 Field Office.                            Bird Treaty Act Consultation.
Pennsylvania State Historic              National Historic Preservation
 Preservation Office (SHPO).              Act, Section 106 Consultation.
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Environmental Mailing List

    This notice is being sent to the Commission's current environmental
mailing list for the Project which includes federal, state, and local
government representatives and agencies; elected officials;
environmental and public interest groups; Native American Tribes; other
interested parties; and local libraries and newspapers. This list also
includes all affected landowners (as defined in the Commission's
regulations) who are potential right-of-way grantors, whose property
may be used temporarily for Project purposes, or who own homes within
certain distances of aboveground facilities, and anyone who submits
comments on the Project and includes a mailing address with their
comments. Commission staff will update the environmental mailing list
as the analysis proceeds to ensure that Commission notices related to
this environmental review are sent to all individuals, organizations,
and government entities interested in and/or potentially affected by
the proposed Project. State and local government representatives should
notify their constituents of this proposed project and encourage them
to comment on their areas of concern.
    If you need to make changes to your name/address, or if you would
like to remove your name from the mailing list, please complete one of
the following steps:
    (1) Send an email to [email protected] stating your
request. You must include the docket number CP22-486-000 in your
request. If you are requesting a change to your address, please be sure
to include your name and the correct address. If you are requesting to
delete your address from the mailing list, please include your name and
address as it appeared on this notice. This email address is unable to
accept comments.

OR

    (2) Return the attached ``Mailing List Update Form'' (appendix 2).

Additional Information

    Additional information about the Project is available from the
Commission's Office of External Affairs, at (866) 208-FERC, or on the
FERC website at www.ferc.gov using the eLibrary link. Click on the
eLibrary link, click on ``General Search'' and enter the docket number
in the ``Docket Number'' field, excluding the last three digits (i.e.,
CP22-486). Be sure you have selected an appropriate date range. For
assistance, please contact FERC Online Support at
[email protected] or<PHONE_NUMBER>, or for TTY, contact (202)
502-8659. The eLibrary link also provides access to the texts of all
formal documents issued by the Commission, such as orders, notices, and
rulemakings.
    Public sessions or site visits will be posted on the Commission's
calendar located at https://www.ferc.gov/news-events/events along with
other related information.

    Dated: August 19, 2022.
Kimberly D. Bose,
Secretary.
[FR Doc. 2022-18335 Filed 8-24-22; 8:45 am]
BILLING CODE 6717-01-P


[Federal Register Volume 83, Number 10 (Tuesday, January 16, 2018)]
[Notices]
[Pages 2278-2282]
[FR Doc No: 2018-00535]

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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-82478; File No. SR-NASDAQ-2017-087]

Self-Regulatory Organizations; The NASDAQ Stock Market LLC; Order
Instituting Proceedings To Determine Whether To Approve or Disapprove a
Proposed Rule Change To Modify the Listing Requirements Related to
Special Purpose Acquisition Companies Listing Standards To Reduce Round
Lot Holders on Nasdaq Capital Market for Initial Listing From 300 to
150 and Eliminate Public Holders for Continued Listing From 300 to
Zero, Require $5 Million in Net Tangible Assets for Initial and
Continued Listing on Nasdaq Capital Market, and Impose a Deadline To
Demonstrate Compliance With Initial Listing Requirements on All Nasdaq
Markets Within 30 Days Following Each Business Combination

January 9, 2018.

I. Introduction

    On September 20, 2017, The NASDAQ Stock Market LLC (``Nasdaq'' or
``Exchange'') filed with the Securities and Exchange Commission
(``Commission''), pursuant to Section 19(b)(1) of the Securities
Exchange Act of 1934 (``Act'') \1\ and Rule 19b-4 thereunder,\2\ a
proposed rule change to modify the listing requirements for Special
Purpose Acquisition Companies (``SPACs'') \3\ listed on the Nasdaq
Capital Market by reducing the number of round lot holders required for
initial listing from 300 to 150, and eliminating the continued listing
requirement for a minimum number of holders, which is also currently
300, that applies until the SPAC completes one or more business
combinations.\4\ Nasdaq also proposes to require that a SPAC listed on
the Nasdaq Capital Market maintain at least $5 million net tangible
assets for initial and continued listing. Finally, Nasdaq is proposing
to allow SPACs listed on any of its three listing tiers (Nasdaq Global
Select, Nasdaq Global, and Nasdaq Capital Market) 30 days to
demonstrate compliance with initial listing requirements following each
business combination.\5\
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    \1\ 15 U.S.C. 78s(b)(1).
    \2\ 17 CFR 240.19b-4.
    \3\ The Commission notes that throughout this order we have used
the term ``SPAC'' or ``SPACs.'' These terms have the same meaning as
``Acquisition Company'' which is the term used by Nasdaq in its
current proposed rule filing.
    \4\ See Nasdaq Rule IM-5101-2(b), and infra note 10 and
accompanying text which describes the requirements for the value of
the business combination(s).
    \5\ The Exchange also proposes to delete a duplicative paragraph
from the rule text and alter the paragraphs formatting within
certain provisions in order to enhance the rule's readability. See
proposed rule text to Nasdaq Rule IM-5101-2 in Exhibit 5 to Nasdaq-
2017-087.
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    The proposed rule change was published for comment in the Federal
Register on October 11, 2017.\6\ On November 22, 2017, the Commission
extended the time period within which to approve the proposed rule
change, disapprove the proposed rule change, or institute proceedings
to determine whether to approve or disapprove the proposed rule change,
to January 9, 2018.\7\ The Commission received six comments on the
proposal.\8\ This order institutes proceedings under Section
19(b)(2)(B) of the Act to determine whether to approve or disapprove
the proposal.
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    \6\ See Securities Exchange Act Release No. 81816 (October 4,
2017), 82 FR 47269 (``Notice'').
    \7\ See Securities Exchange Act Release No. 82142, 82 FR 56293
(November 28, 2017).
    \8\ See Letters to Brent J. Fields, Secretary, Commission, from
Jeffrey M. Solomon, Chief Executive Officer, Cowen and Company, LLC,
dated October 19, 2017 (``Cowen Letter''); Jeffrey P. Mahoney,
General Counsel, Council of Institutional Investors, dated October
25, 2017 (``CII Letter''); Sean Davy, Managing Director, Capital
Markets Division, SIFMA, dated October 31, 2017 (``SIFMA Letter'');
Akin Gump Strauss Hauer & Feld LLP, dated November 1, 2017 (``Akin
Gump Letter''); Steven Levine, Chief Executive Officer,
EarlyBirdCapital, Inc., dated November 3, 2017 (``EarlyBird
Letter''); and Christian O. Nagler and David A. Curtiss, Kirkland &
Ellis LLP, dated November 9, 2017 (``Kirkland Letter'').
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II. Description of Proposal

A. Background on SPACs

    A SPAC is a special purpose company whose business plan is to raise
capital in an initial public offering (``IPO'') and, within a specific
period of time, engage in a merger or acquisition with one or more
unidentified companies. Among other things, a SPAC must keep 90% of the
gross proceeds of its IPO in an escrow account through the date of a
business combination.\9\ The SPAC must complete one or more business
combinations, having an aggregate market value of at least 80% of the
value of the deposit account at the time of the agreement to enter into
the initial combination, within 36 months of the effectiveness of the
IPO registration statement.\10\ Additionally, public shareholders who
object to a business combination have the right to convert their common
stock into a pro rata share of the funds held in escrow.\11\ Following
each business combination the combined company must meet the Exchange's
requirements for initial listing of an operating company, including the
requirement to maintain a minimum of 300 holders.\12\
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    \9\ See Nasdaq Rule IM-5101-2(a).
    \10\ See Nasdaq Rule IM-5101-2(b). For purposes of this rule, in
calculating the 80% value of the deposit account any deferred
underwriter fees and taxes payable on the income earned on the
deposit account are excluded.
    \11\ See Nasdaq Rule IM-5101-2(d) & Nasdaq Rule IM-5101-2(e). If
a shareholder vote is taken however, under Nasdaq Rule IM-5101-2(d),
the right of shareholders voting against a business combination to
redeem their shares for cash may be subject to a limit established
by the SPAC (that can be set no lower than 10% of the shares sold in
the IPO).
    \12\ See Nasdaq Rule IM-5101-2(d) & Nasdaq Rule IM-5101-2(e) and
Nasdaq Rules 5505(a)(3) and 5550(a)(3).
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B. Description of Proposed Changes to SPAC Listing Standards

    The Exchange has proposed to reduce the number of round lot holders
required for SPACs initially listing on the Nasdaq Capital Market from
300 to 150.\13\ The Exchange also proposed to completely eliminate the
current continued listing requirement that there be a minimum of 300
holders until such time as the SPAC completes one or more business
combinations.\14\ In support of this proposal, as set forth in more
detail in the Notice, Nasdaq states that SPACs often have difficulty
demonstrating compliance with these initial and continued listing
standards. Based on conversations with market participants, Nasdaq
believes this is due to the unique nature of SPACs, and asserts that
this limits the number of interested retail investors and encourages
owners to hold their shares until an acquisition is announced, which
can be as long as three years after the IPO. Nasdaq believes that these
same features limit the benefit to investors of having a shareholder
requirement, the purpose of which, according to Nasdaq, is ``to help
ensure that a stock has an investor following and liquid market
necessary for trading.'' \15\ Among other things, Nasdaq asserted that
``the potential for distorted prices occurring as a result of there
being few shareholders or illiquidity is less of a concern for [a
SPAC's] investors'' because, in the period prior to the business

combination, ``the value of [a SPAC] is based primarily on the value of
the funds it held in trust,'' and ``shareholders have the right to
redeem their shares for a pro rata share of that trust in conjunction
with the business combination.'' \16\ As a result, according to Nasdaq,
SPACs generally ``have historically traded close to the value in the
trust, even when they have had few shareholders, which suggests that
their lack of shareholders has not resulted in distorted prices and the
associated concerns.'' \17\ Nasdaq notes that SPACs ``must undergo a
transformative transaction within 36 months of listing, at which time
they must meet all listing requirements, including the shareholder
requirement.'' \18\ In Nasdaq's view, ``[t]his provides an additional
protection to shareholders, assuring that any liquidity issues are only
temporary.'' \19\ Finally, Nasdaq observes that ``it can be difficult
for a company, once listed, to obtain evidence demonstrating the number
of its shareholders because many accounts are held in street name'' and
that this process ``is particularly burdensome for [SPACs] because most
operating expenses are typically borne by the [SPAC's] sponsors due to
the requirement that the gross proceeds of the initial public offering
remain in the trust account until the closing of the business
combination.'' \20\
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    \13\ See proposed rule text to Nasdaq Rule 5505(a)(3) in Exhibit
5 to Nasdaq-2017-087.
    \14\ See proposed rule text to Nasdaq Rule 5550(a)(3) in Exhibit
5 to Nasdaq-2017-087. Nasdaq Rule 5550(a)(3) currently requires 300
public holders for continued listing of a primary equity security
listed on Nasdaq Capital Markets. ``Public Holders'' is defined to
mean holders of a security that includes both beneficial holders and
holders of record, but does not include any holder who is, either
directly or indirectly, an executive officer, director, or the
beneficial holder of more than 10% of the total shares outstanding.
See Nasdaq Rule 5005(a)(35).
    \15\ See Notice at 47269.
    \16\ See Notice at 47269. See also, supra note 11, that refer to
possible limits on the amount of shares that can be redeemed on a
pro rata basis.
    \17\ See Notice at 47269.
    \18\ See Notice at 47269-70.
    \19\ See Notice at 47270.
    \20\ Id.
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    The Exchange also proposed to add a new requirement for SPACs to
list, and remain listed, on the Nasdaq Capital Market that would
require SPACs to maintain at least $5 million in net tangible
assets.\21\ This requirement is being proposed by Nasdaq as an
alternative exception to the Commission's penny stock rule, Rule 3a51-1
under the Act, because Nasdaq's proposed changes to the minimum number
of holders would result in SPACs listed on the Nasdaq Capital Market no
longer qualifying for the current penny stock rule exception that
requires listed companies to have 300 round lot holders.\22\ The $5
million net tangible assets requirement is an alternative exception to
the penny stock rule, and ``Nasdaq believes that all [SPACs] currently
listed satisfy this alternative.'' \23\ The Exchange stated that it
will monitor listed SPACs for compliance with this requirement and, to
assist broker-dealers in complying with the penny stock rule, will
publish on Nasdaq's website a daily list of any SPAC that no longer
meets the net tangible assets requirement, and which does not satisfy
any other penny stock exception. Further, if a SPAC does not meet the
net tangible assets requirement, the Exchange would initiate delisting
proceedings under the Nasdaq Rule 5800 Series.\24\
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    \21\ Net Tangible Assets is defined as total assets less
intangible assets and liabilities. See proposed Nasdaq Rule IM-5101-
2(f). Under the proposal, if a company is listed prior to approval
of the Exchange's proposal it will not need to satisfy this net
tangible asset requirement if it has a least 300 public holders.
    \22\ Rule 15g-1 through 15g-9 under the Act impose certain
disclosure and additional requirements on brokers and dealers when
effecting transactions in penny stocks. See 17 CFR 240.15g-1 to 15g-
9. Rule 3a51-1 includes an exception from the definition of penny
stock for securities registered on a national securities exchange
that has initial listing standards, among others, that requires at
least 300 round lot holders. Rule 3a51-1 also has an exception from
the penny stock definition if a company has $5 million in net
tangible assets. See 17 CFR 240.3a51-1(a) and 17 CFR 240.3a51-1(g).
    \23\ See Notice at 47270 in footnote 16.
    \24\ The SPAC is able to request review of the Staff Delisting
Determination which would allow it to remain listed for a maximum of
180 calendar days. See Nasdaq Rule 5815. The Exchange states that
this limitation will only allow for a SPAC to remain listed for a
short period of time and that the process would provide notice to
the public. See Notice at 47271.
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    Finally, the Exchange proposed to add a requirement, applicable to
all of its listing tiers (Nasdaq Global Select, Nasdaq Global, and
Nasdaq Capital Market),that a listed SPAC must demonstrate that it
meets all initial listing requirements within 30 days following each
business combination. The Exchange notes that, under its existing
rules, following a business combination with a SPAC, ``the resulting
company must satisfy all initial listing requirements.'' \25\ The
Exchange takes the position that ``[t]he rule does not provide a
timetable for the company to demonstrate that it satisfies those
requirements,'' so ``Nasdaq proposes to codify that a company must
demonstrate that it meets the initial listing requirements within 30
days following a business combination.'' \26\ If the SPAC has not
demonstrated that it meets all of the initial listing requirements
within 30 days following a business combination, then Nasdaq staff
would issue a Delisting Determination under the Nasdaq Rule 5800
Series.\27\
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    \25\ See Notice at 47271. See also Nasdaq Rule IM-5101-2 (d).
    \26\ See Notice at 47271.
    \27\ See Notice at 47271. Nasdaq also proposed other non-
substantive changes in its proposal. See also supra note 5.
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III. Summary of Comments

    The Commission received six comment letters on the proposal.\28\
Five commenters expressed support for the proposed rule change,\29\ and
one commenter did not.\30\
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    \28\ See supra note 8.
    \29\ See Cowan Letter at 1; CII Letter at 4; SIFMA Letter at 2;
Akin Gump Letter at 3; EarlyBird Letter at 1; Kirkland Letter at 1.
    \30\ See CII Letter at 1 (requesting more fulsome information
and analysis on both proposed holder changes and the proposal to
adopt as a listing standard the net tangible assets penny stock
exemption).
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    The commenters supporting the proposed rule change generally
discussed the importance of SPACs as an alternative to a traditional
IPO as a path for a company to go public,\31\ and expressed the view
that the proposal would reduce burdens on SPACs and facilitate their
ability to go public, without undermining investor protections.\32\
With respect to the proposed changes to the required minimum number of
holders, two commenters indicated that reducing these requirements
would lessen the costs and administrative burdens on SPACs, which
operate with limited funds not held in escrow, to monitor the number of
holders.\33\ Two commenters asserted that SPACs generally are marketed
to institutions, and not retail investors, so that the proposed changes
would not harm retail investors.\34\ Another commenter expressed the
view that it can be difficult for SPACs to meet the existing minimum
number of holders requirements ``due to the high demand from
institutional investors in the IPO allocation process.'' \35\ Two
commenters believed that, given the unique characteristics of SPACs
(e.g., the requirement to complete a business combination within a
specified time period, the right of shareholders to a pro rata share of
the funds held in escrow, and the tendency to hold shares until a
business combination is announced), the minimum number of holder

requirements did not provide significant investor protection
benefits.\36\
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    \31\ See Cowan Letter at 1; SIFMA Letter at 2 (stating 20
percent of public offerings in the first three quarters of 2017 came
from SPACs); EarlyBird Letter at 1; Kirkland Letter at 1.
    \32\ See SIFMA Letter at 2; EarlyBird Letter at 1; Akin Gump
Letter at 3.
    \33\ See SIFMA Letter at 3 (stating the proposed change would
``reduce costs and burdens on [SPACs]'' which ``have limited funds
not held in escrow''); Akin Gump Letter at 2 (arguing the holder
requirement ``creates significant administrative burden on SPACs''
which are ``operating with limited funds outside of the trust
account'').
    \34\ See Cowen Letter at 1 and EarlyBird Letter at 1.
    \35\ See Akin Gump Letter at 2.
    \36\ See SIFMA Letter at 3 (stating the pro rata right to funds
held in the escrow account, the limited amount of time that the SPAC
has to complete a business combination and the unique trading
fundamentals indicate why a lower or no holder requirement should be
required). See also Akin Gump Letter at 2 (asserting that ``SPAC
investors have further protection from illiquidity because a SPAC
must undergo a business combination within the allotted time period
or liquidate and return the pro rata share of the trust assets to
public investors.'').
---------------------------------------------------------------------------

    Two commenters specifically supported the $5 million net tangible
assets requirement, noting that this requirement should help SPACs
avoid being designated a ``penny stock.'' \37\ One commenter noted the
proposal by Nasdaq to publish a daily list of SPACs that do not meet
the requirement for an exception to the penny stock rules will ensure
proper notice is provided to market participants.\38\
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    \37\ See SIFMA Letter at 4; and Akin Gump Letter at 3.
    \38\ See Akin Gump Letter at 3.
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    Finally, three of the commenters supporting the proposed rule
change also specifically supported the proposal to establish a 30-day
period for a listed SPAC to demonstrate compliance with initial listing
requirements following a business combination.\39\ One commenter
believed that this ``strikes a balance of providing the company with
necessary time to manage its limited resources while protecting
investors in the same way [Nasdaq] protects investors in operating
companies that are conducting their initial public offerings.'' \40\
Another commenter expressed the view that the 30-day compliance period
``would be important to allow [SPACs] time to satisfy the listing
requirements after the closing of an initial business combination,''
given ``the uncertainty in stock ownership that redemption elections
can bring.'' \41\
---------------------------------------------------------------------------

    \39\ See SIFMA Letter at 4; Akin Gump Letter at 3; Kirkland
Letter at 1.
    \40\ See SIFMA Letter at 4.
    \41\ See Kirkland Letter at 1.
---------------------------------------------------------------------------

    One commenter did not support the proposed rule change, noting that
``it does not provide sufficient information for us to make a
determination as to whether our members and the capital markets would
benefit from the proposed rule changes.'' \42\ Areas where this
commenter believed more evidence was necessary include: (1) The
assertion that price distortions or illiquidity are a lesser concern
for SPACs; (2) the analysis that SPACs trade close to the redemption
value of the assets held in trust; (3) the number of companies
constrained by existing listing standards; and (4) the difficulties
demonstrating compliance with existing listing standards, including
determining the number of holders.\43\
---------------------------------------------------------------------------

    \42\ See CII Letter at 1.
    \43\ See CII Letter at 2. This commenter specifically indicated,
however, that it did support the proposal to allow listed companies
30 days to demonstrate compliance with the initial listing standards
after the consummation of the SPAC's business combination.
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IV. Proceedings To Determine Whether To Approve or Disapprove SR-
NASDAQ-2017-087 and Ground for Disapproval Under Consideration

    The Commission is instituting proceedings pursuant to Section
19(b)(2)(B) of the Act to determine whether the proposal should be
approved or disapproved.\44\ Institution of such proceedings is
appropriate at this time in view of the legal and policy issues raised
by the proposal, as discussed below. Institution of disapproval
proceedings does not indicate that the Commission has reached any
conclusions with respect to any of the issues involved.
---------------------------------------------------------------------------

    \44\ 15 U.S.C. 78s(b)(2)(B).
---------------------------------------------------------------------------

    Pursuant to Section 19(b)(2)(B) of the Act, the Commission is
providing notice of the grounds for disapproval under consideration.
The Commission is instituting proceedings to allow for additional
analysis and input concerning the proposed rule change's consistency
with the Act \45\ and, in particular, with Section 6(b)(5) of the Act,
which requires, among other things, that the rules of a national
securities exchange be designed to prevent fraudulent and manipulative
acts and practices, to promote just and equitable principles of trade,
to remove impediments to and perfect the mechanism of free and open
market and a national market system, and, in general, to protect
investors and the public interest.\46\
---------------------------------------------------------------------------

    \45\ 15 U.S.C. 78f(b)(5).
    \46\ Id.
---------------------------------------------------------------------------

    The Commission has consistently recognized the importance of the
minimum number of holders and other similar requirements in exchange
listing standards.\47\ Among other things, such listing standards help
ensure that exchange listed companies have sufficient public float,
investor base, and trading interest to provide the depth and liquidity
necessary to promote fair and orderly markets.\48\
---------------------------------------------------------------------------

    \47\ For example, the Commission has repeatedly stated in
approving exchange listing requirements, including Nasdaq's original
SPAC listing standards, that the development and enforcement of
adequate standards governing the listing of securities on an
exchange is an activity of critical importance to financial markets
and the investing public. See e.g., Securities Exchange Act Release
No. 57785 (May 6, 2008), 73 FR 27597 (May 13, 2008) (stating also
that the distribution standards, which include exchange holder
requirements, ``. . . should help to ensure that the [SPACs]
securities have sufficient public float, investor base, and
liquidity to promote fair and orderly markets''); Securities
Exchange Act Release No. 58228 (July 25, 2008), 73 FR 44794 (July
31, 2008).
    \48\ Id. The Commission has further stated that once a security
has been approved for initial listing, maintenance criteria allow an
exchange to monitor the status and trading characteristics of that
issue to ensure that it continues to meet the exchange's standards
for market depth and liquidity so that fair and orderly markets can
be maintained. See e.g., Securities Exchange Act Release No. 57785
(May 6, 2008), 73 FR 27597 (May 13, 2008) also stating that the
continued listing standards for SPACs, which include the holder
requirements, protect investors and promote fair and orderly
markets.
---------------------------------------------------------------------------

    Nasdaq proposes to lower the minimum number of holders required for
initial listing of a SPAC from 300 to 150, and to eliminate the
continued listing requirement to have a minimum number of holders until
the SPAC completes a business acquisition. In support of its proposal,
Nasdaq asserts that SPACs often have difficulty demonstrating
compliance with the minimum number of holders requirements because many
accounts are held in street name, so that this information must be
obtained from broker-dealers and other third parties. Nasdaq states
that this effort is particularly burdensome for SPACs because most of
the expenses incurred in determining the number of holders must be
borne by the SPAC's sponsors. The Commission notes that the vast
majority of shares of most listed companies are held in street name,
and it is not clear from Nasdaq's proposal how the burdens on SPACs in
determining the number of holders are different than for listed
companies generally, other than the fact that the SPAC's sponsor bears
most of the costs. In addition, as noted by a commenter, it is not
clear from Nasdaq's proposal the extent to which SPACs actually have
had difficulties complying with the existing minimum number of holders
requirements.\49\
---------------------------------------------------------------------------

    \49\ See supra note 43.
---------------------------------------------------------------------------

    Nasdaq also takes the position that the benefits of the minimum
number of holders requirements are less with SPACs because their value
is based primarily on the value of the funds held in trust. Nasdaq
notes that SPACs historically have traded close to the value of the
funds held in trust, and concludes that a lack of shareholders has not
resulted in distorted prices and the associated concerns. The
Commission, however, does not believe it is clear from Nasdaq's
proposal how these historic trading patterns bear on the role of the
minimum number of holders requirements in maintaining fair and orderly
markets, particularly since

Nasdaq's observations were made while the current minimum number of
holder requirements were in place.
    Finally, Nasdaq proposes to allow a listed SPAC an additional 30
days following a business combination to demonstrate compliance with
all initial listing standards, including the holder requirement. Nasdaq
acknowledges that, following a business combination, the SPAC should
meet all applicable listing requirements for operating companies,
including the requirement to maintain a minimum of 300 holders on an
initial and continued basis. Nasdaq takes the position that it is
proposing the 30-day transition period because the current rule ``does
not provide a timetable'' for the SPAC to demonstrate compliance. The
Commission notes that initial listing standards, absent an explicit
exception, apply upon initial listing. Further, the Commission notes
that, because the same number of holders today (i.e., 300) applies to
SPACs listed on Nasdaq before and after a business combination,\50\ the
issue of a post-combination transition period has not been raised.
Nasdaq proposes to eliminate the continued listing requirement for
SPACs, so that a listed SPAC with very few holders may need to have at
least 300 holders a short time after a business combination. The
Commission does not believe it is clear from Nasdaq's proposal that
such a structure is workable, or how a listed SPAC would ensure it is
in a position to sufficiently increase its number of holders.
---------------------------------------------------------------------------

    \50\ The Commission recognizes that the initial holder
requirement is 300 round lot holders while the continued listing
requirement is 300 public holders. Therefore, when a SPAC
transitions to listing as an operating company after a business
combination, it should have at least 300 public holders, many of
which may also be round lot holders.
---------------------------------------------------------------------------

V. Commission's Solicitation of Comments

    The Commission requests that interested persons provide written
submissions of their views, data, and arguments with respect to the
issues identified above, as well as any other concerns they may have
with the proposal. In particular, the Commission invites the written
views of interested persons concerning whether the proposal is
consistent with Section 6(b)(5), or any other provision of the Act, or
the rules and regulations thereunder. Although there do not appear to
be any issues relevant to approval or disapproval that would be
facilitated by an oral presentation of views, data, and arguments, the
Commission will consider, pursuant to Rule 19b-4, any request for an
opportunity to make an oral presentation.\51\
---------------------------------------------------------------------------

    \51\ Section 19(b)(2) of the Exchange Act, as amended by the
Securities Act Amendments of 1975, Public Law 94-29 (June 4, 1975),
grants the Commission flexibility to determine what type of
proceeding--either oral or notice and opportunity for written
comments--is appropriate for consideration of a particular proposal
by a self-regulatory organization. See Securities Act Amendments of
1975, Senate Comm. on Banking, Housing & Urban Affairs, S. Rep. No.
75, 94th Cong., 1st Sess. 30 (1975).
---------------------------------------------------------------------------

    Interested persons are invited to submit written data, views, and
arguments regarding whether the proposal should be approved or
disapproved by February 6, 2018. Any person who wishes to file a
rebuttal to any other person's submission must file that rebuttal by
February 20, 2018. The Commission asks that commenters address the
sufficiency of the Exchange's statements in support of the proposal
which are set forth in the Notice, in addition to any other comments
they may wish to submit about the proposed rule change. In particular,
the Commission seeks comment, including where relevant, any specific
data, statistics, or studies, on the following:
    1. Would the proposal ensure that a sufficient liquid market exists
for the shares of SPACs on the Nasdaq Capital Market? Why or why not?
    2. Without any continued listing holder requirement, would the
shares of SPACs still trade close to their redemption value, as the
Exchange has stated? If yes, would that trading pattern continue after
an announcement of a business combination?
    3. Without any continued listing holder requirement, could shares
of SPACs be more prone to manipulation, either post-IPO or at the time
of the business combination announcement (but before consummation of
the business combination)?
    4. Has the Exchange demonstrated with specific data, analysis, and
studies that the shares of SPACs trade consistently as stated in the
proposal, and does the analysis support the proposed reductions in the
holder initial and continued listing standards? If not, what data
should be reviewed and analyzed? For example, in the Exchange's
examination of SPACs that were below the continued public holder
listing requirement, how few shareholders did these SPACs have?
    5. The Exchange asserted that it is time consuming and burdensome
for a SPAC to obtain a list of shareholders to demonstrate the number
of holders, because many shares are held in street name with broker-
dealers. The Commission notes that the process of obtaining number of
shareholders is similar for all listed companies. Do commenters think
SPACs are particularly burdened by this process and the costs? Is the
fact the costs are usually borne by the sponsors relevant?
    Comments may be submitted by any of the following methods:

Electronic Comments

     Use the Commission's internet comment form (http://www.sec.gov/rules/sro.shtml); or
     Send an email to [email protected]. Please include
File Number SR-NASDAQ-2017-087 on the subject line.

Paper Comments

     Send paper comments in triplicate to Secretary, Securities
and Exchange Commission, 100 F Street NE, Washington, DC 20549-1090.

All submissions should refer to File Number SR-NASDAQ-2017-087. This
file number should be included on the subject line if email is used. To
help the Commission process and review your comments more efficiently,
please use only one method. The Commission will post all comments on
the Commission's internet website (http://www.sec.gov/rules/sro.shtml).
Copies of the submission, all subsequent amendments, all written
statements with respect to the proposed rule change that are filed with
the Commission, and all written communications relating to the proposed
rule change between the Commission and any person, other than those
that may be withheld from the public in accordance with the provisions
of 5 U.S.C. 552, will be available for website viewing and printing in
the Commission's Public Reference Room, 100 F Street NE, Washington, DC
20549, on official business days between the hours of 10:00 a.m. and
3:00 p.m. Copies of such filing also will be available for inspection
and copying at the principal office of the Exchange. All comments
received will be posted without change; the Commission does not edit
personal identifying information from submissions. You should submit
only information that you wish to make available publicly. All
submissions should refer to File Number SR-NASDAQ-2017-087 and should
be submitted on or before February 6, 2018.

    For the Commission, by the Division of Trading and Markets,
pursuant to delegated authority.\52\
---------------------------------------------------------------------------

    \52\ 17 CFR 200.30-3(a)(12).
---------------------------------------------------------------------------

Eduardo A. Aleman,
Assistant Secretary.
[FR Doc. 2018-00535 Filed 1-12-18; 8:45 am]
 BILLING CODE 8011-01-P


Technical Support Document for the Final Clean Air Interstate Rule Modeling of Control Costs, Emissions, and Control Retrofits for Cost Effectiveness and Feasibility Analyses EPA Docket number: OAR 2003 0053 March, 2005 U. S. Environmental Protection Agency Office of Air and Radiation 2 Modeling of Control Costs, Emissions, and Control Retrofits for Cost Effectiveness and Feasibility Analyses Overview This Technical Support Document ( TSD) describes EPA's use of the Integrated Planning Model ( IPM) to develop estimates of SO2 and NOx emission control costs, projections of future emissions and emission reductions, and projections of capacity of future control retrofits, assuming controls on electricity generating units ( EGUs). This TSD also describes EPA's use of the Technology Retrofitting Updating Model ( TRUM) to develop marginal cost effectiveness curves for SO2 and NOx reductions from EGUs.

The EPA used IPM projections and TRUM marginal cost curves to conduct analyses contained in the CAIR Notice of Final Rulemaking ( NFR) preamble in section IV, which is entitled " What Amounts of SO2 and NOx Emissions Did EPA Determine Should Be Reduced?" Specifically, EPA used these control cost estimates and marginal cost effectiveness curves to analyze the cost effectiveness of CAIR, as presented in section IV. A of the NFR preamble. Additionally, the Agency used the projections of control retrofit capacities to analyze the feasibility of CAIR, as presented in preamble section IV. C.

This TSD provides background on the IPM and TRUM models, and explains the following specific analyses for the CAIR NFR:

° Use of IPM to estimate average and marginal costs of SO2 and NOx controls ° Use of IPM to project future SO2 and NOx emissions and emission reductions ° Use of IPM to project capacity of future SO2 and NOx control retrofits ° Use of TRUM to examine changes in marginal costs at varying levels of SO2 and NOx reduction Background on EPA's IPM Analyses EPA uses the Integrated Planning Model ( IPM) to examine costs and, more broadly, analyze the projected impact of environmental policies on the electric power sector in the 48 contiguous States and the District of Columbia. The IPM is a multi regional, dynamic, deterministic linear programming model of the U. S. electric power sector. It provides forecasts of least cost capacity expansion, electricity dispatch, and emission control strategies for meeting energy demand and environmental, transmission, dispatch, and reliability constraints. The National Electric Energy Data System ( NEEDS) contains the generation unit records used to construct model plants that represent existing and planned/ committed units in EPA modeling applications of IPM. The NEEDS 2004 includes basic geographic, operating, air emissions, and other data on all the generation units that are represented by model plants in EPA's version 2.1.9 update of IPM. Documentation for IPM, and the NEEDS database, are available in the CAIR rulemaking docket and also on EPA's website at www. epa. gov/ airmarkets/ epa ipm/ . 3 1 An exception was made to the run year mapping for an IPM sensitivity run that examined the impact of a NOx Compliance Supplement Pool ( CSP). In that run the years 2009 through 2012 were mapped to 2010 and 2008 was mapped to 2008. Modeling applications of IPM produce forecasts for model plants, i. e., clusters of real life electricity generating units with similar characteristics. The model plant projections can be used to produce parsed results, which are unit level results derived from the model plant projections. Projections for individual plants are based on data currently available and modeling parameters which are simplifications of the real world. It is likely that some future actions regarding individual plants could differ from model projections of actions; however, the aggregate impacts are expected to be appropriately characterized by the model. Where appropriate, EPA produced parsed results from IPM runs for use in analyzing CAIR.

The EPA used IPM to evaluate the cost and emissions impacts of the policies to limit annual emissions of SO2 and NOx, and ozone season emissions of NOx, that are required by CAIR   if all affected States choose to implement reductions by controlling EGUs   to be made from the electric power sector. For the CAIR Notice of Proposed Rulemaking ( NPR), EPA used IPM version 2.1.6 and NEEDS 2003 to analyze cost and emissions impacts of the proposed rule. For the CAIR NFR, EPA updated IPM and NEEDS. The updated versions are named IPM version 2.1.9 and NEEDS 2004. This TSD describes the IPM runs that EPA used to estimate average and marginal costs of EGU controls, emissions and emission reductions, and control retrofits for the CAIR NFR.

The Regulatory Impact Analysis ( RIA) for the CAIR NFR includes a list and description of each IPM run that supports EPA's analysis for the NFR ( see RIA Table D 9). Data files for each of the IPM runs that EPA used for the NFR are available in the CAIR docket as well as on EPA's website. This TSD provides some additional description regarding the particular IPM runs that EPA used for its cost effectiveness and feasibility analyses, which are presented in section IV of the CAIR NFR preamble. Data files for the runs described in this TSD are available in the CAIR docket and on EPA's website, along with the other runs used for the NFR.

The IPM uses model run years to represent the full planning horizon being modeled. That is, several years in the planning horizon are mapped into a representative model run year, enabling IPM to perform multiple year analyses while keeping the model size manageable. Although IPM reports results only for model run years, it takes into account the costs in all years in the planning horizon. In EPA's v. 2.1.9 update of IPM, the years 2008 through 2012 are mapped to run year 2010, and the years 2013 through 2017 are mapped to run year 2015.1 In the CAIR NFR preamble, section IV, model outputs for 2009 and 2010 are from the 2010 run year, and model outputs for 2015 are from the 2015 model run year.

In its IPM modeling, EPA assumes interstate emissions trading for EGUs. Although States are not required to participate in an interstate EGU emissions trading program, EPA believes it is reasonable to evaluate control costs assuming States choose to participate in such a program since 4 2 The District of Columbia and the following 23 States must reduce annual SO2 and NOx emissions: Alabama, Florida, Georgia, Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West Virginia, and Wisconsin. The District of Columbia and the following 25 States must reduce ozone season NOx emissions: Alabama, Arkansas, Connecticut, Delaware, Florida, Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, Massachusetts, Michigan, Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Virginia, West Virginia, and Wisconsin.

3 The EPA began its emissions and economic analyses for CAIR before the air quality analyses, which affect the States covered by the final rule, was completed. that will result in less expensive reductions. Also, note that EPA's IPM modeling accounts for the use of the existing title IV bank of SO2 allowances.

The final CAIR requires annual SO2 and NOx reductions in 23 States and the District of Columbia, and also requires ozone season NOx reductions in 25 States and the District of Columbia. Many of the CAIR States are affected by both the annual SO2 and NOx reduction requirements, and the ozone season NOx requirements. 2 The EPA initially conducted IPM modeling for the final CAIR using a control strategy that is similar but not identical to the final CAIR requirements. 3 The control strategy that EPA initially modeled included three additional States ( Arkansas, Delaware and New Jersey) within the region required to make annual SO2 and NOx reductions, however these three States are not required to make annual reductions under the final CAIR. The addition of these three States made a total of 26 States and the District of Columbia affected by annual SO2 and NOx caps for the initial model run. ( Note that EPA is proposing to require annual SO2 and NOx reductions in Delaware and New Jersey.) The initial model run also included individual State ozone season NOx caps for Connecticut and Massachusetts, and did not include ozone season NOx caps for any other States. Several of the analyses for the final CAIR are based on this initial model run. In this TSD, we refer to this initial model run as the " CAIR 2004 analysis" run.

The Agency conducted revised final IPM modeling that reflects the final CAIR control requirements. The final IPM modeling includes regionwide annual SO2 and NOx caps on the 23 States and the District of Columbia that are required to make annual reductions, and includes a regionwide ozone season NOx cap on the 25 States and the District of Columbia that are required to make ozone season reductions. The EPA modeled the final CAIR NOx strategy as an annual NOx cap with a nested, separate ozone season NOx cap. In this TSD, we refer to this final model run as the " final CAIR policy."

The analyses in section IV of the CAIR NFR preamble are generally derived from the final CAIR policy run reflecting the final CAIR. However, some of EPA's analyses are based on the original CAIR policy run that reflected a similar but not identical control strategy to the final CAIR. Below, EPA explains how each IPM run was used for the analyses in section IV of the preamble. 5 Note that the air quality analyses in section VI in the NFR preamble and the benefits analysis in section X, as well as the analyses presented in the Regulatory Impact Analysis ( RIA), are based on emissions projections from the initial CAIR policy run ( the CAIR 2004 analysis run). As explained in section IV in the preamble, EPA believes that the differences between the CAIR 2004 analysis run and the final CAIR policy run have very little impact on projected control costs and emissions.

In section IV in the CAIR NFR preamble, EPA summarizes some cost and emissions projections that were previously presented in the NPR ( published January 30, 2004). The IPM runs that the Agency used to develop those NPR cost and emissions projections were described in the NPR and in a supporting memo available in the CAIR docket ( the memo is entitled " Memorandum to the OAR Docket from USEPA, Clean Air Markets Division re: Integrated Planning Model ( IPM) Runs used in Developing the Proposed Interstate Air Quality Rule ( IAQR) Emission Reduction and Cost effectiveness Estimates," dated January 28, 2004). This TSD does not repeat descriptions of IPM runs from the NPR.

Here is a description of how EPA estimated control costs, emissions projections, and retrofit projections, using outputs from IPM runs: ° Marginal control costs. In the IPM runs, the marginal cost reflects what it would cost to obtain one additional ton of reduction beyond the amount reduced by the modeled control scenario, in a particular model run year. The marginal cost can be read directly as an output in the Environmental Measures Report, where it is labeled " constraint shadow price." ° Average control costs. To estimate average control costs, EPA compares the total annual production costs from a single pollutant policy run to the Base Case run ( for a particular model run year) and compares the total ( SO2 or NOx) emissions from the single pollutant policy run to the Base Case run, then divides the difference in production costs to the difference in emissions to get dollars/ ton. The total annual production costs and total emissions are found in the Regional Summary Report. The total annual production cost in the Regional Summary Report does not include the cost of combustion controls because that cost is not included in IPM, but rather is calculated exogenously. See Table 1 in this TSD for combustion control costs that EPA used to calculate average control cost estimates presented in section IV in the NFR preamble. ° Emissions and Emission Reductions. The total emissions of SO2 or NOx emitted by all affected units in a particular policy scenario can be found in the Environmental Measures Report, listed under the specific policy constraint of interest. If a parsed file is produced, then the emissions at affected units can also be determined by summing the emissions for all affected units from the parsed file. ( The emissions totals that are found in the Regional Summary Report are total national emissions   not only at affected plants.) To estimate emission reductions, EPA calculates the difference between the emissions in the Base Case run and the emissions in a policy case run. ° Control Retrofits. The capacity and type of emission control retrofits are found in the Regional Summary Report. 6 Description of IPM Runs Used to Estimate Control Costs and Emissions IPM Run ID: Base Case 2004 Description: EPA Base Case for 2004 Analyses This is the Base Case model run, which includes the national title IV SO2 cap and trade program, NOx SIP Call regional ozone season cap and trade program, and State specific programs in Connecticut, Illinois, Maine, Massachusetts, Minnesota, Missouri, New Hampshire, New York, North Carolina, Oregon, Texas, and Wisconsin. New Source Review ( NSR) settlement actions are included, as they existed on March 19, 2004 ( see Exhibit 3 15 in the IPM v. 2.1.9 Documentation Summary for more information about NSR settlements in the Base Case). This IPM run represents conditions without CAIR and without future State SIP actions for ozone and PM2.5. The EPA used the Base Case run to compare costs and emissions to CAIR policy runs in order to estimate average costs of CAIR, to present estimated emissions under Base Case conditions and estimated reductions under CAIR, and to estimate costs of some State programs. The EPA used parsed files produced from this IPM run to analyze State level emission projections.

IPM Run ID: CAIR 2004_ Analysis Description: CAIR 2004 Analysis Run This is the initial CAIR policy run, which EPA used for several analyses for the final CAIR. As explained above, EPA initially conducted IPM modeling for the final CAIR using a control strategy that is similar but not identical to the final CAIR requirements. This run included three additional States ( Arkansas, Delaware, and New Jersey) within the region required to make annual SO2 and NOx reductions, although these three States are not required to make annual reductions under the final CAIR. With the addition of these 3 States, a total of 26 States and the District of Columbia are affected by annual SO2 and NOx caps in this run. In addition, this run included individual State ozone season NOx caps for Connecticut and Massachusetts, and did not include ozone season NOx caps for any other States.

Note that EPA is proposing to include 2 additional States   Delaware and New Jersey   with the CAIR region required to make annual SO2 and NOx emission reductions. Because the CAIR 2004 analysis run capped annual SO2 and NOx emissions in Arkansas, Delaware, and New Jersey, the original run is quite similar to what the final requirements will be if EPA's proposal to require annual reductions in those 2 additional States is finalized ( although EPA is not proposing annual caps on emissions in Arkansas). However, the CAIR 2004 analysis run imposed ozone season NOx caps on Connecticut and Massachusetts only, whereas the final CAIR requires ozone season caps on all of the 25 States and DC that are affected by CAIR for ozone. The IPM run called CAIR 2004_ Final_ DE and NJ, described below, represents what the CAIR requirements will be if EPA finalizes its proposal to require annual SO2 and NOx reductions in Delaware and New Jersey, and that run includes an ozone season cap on all 25 States and DC that are affected by CAIR for ozone.

The Agency conducted revised final IPM modeling that reflects the final CAIR requirements. The IPM run that reflects the final CAIR policy is called run CAIR 2004_ Final, which is described 7 below. Cost and emissions projections for CAIR, as presented in section IV of the CAIR NFR preamble, are derived from the final CAIR policy run. However, some of the sensitivity analyses were developed using IPM runs that are based on the CAIR 2004 analysis run.

IPM Run ID: CAIR 2004_ Final Description: Final CAIR Policy Run This is the final CAIR policy run. This run includes regionwide annual SO2 and NOx caps on the 23 States and the District of Columbia that are required to make annual reductions, and includes a regionwide ozone season NOx cap on the 25 States and the District of Columbia that are required to make ozone season reductions. This run includes an annual NOx cap and a nested, separate ozone season NOx cap.

The District of Columbia and the following 23 States are included in regionwide annual SO2 and NOx caps in this run: Alabama, Florida, Georgia, Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West Virginia, and Wisconsin.

The District of Columbia and the following 25 States are included in regionwide ozone season NOx caps in this run: Alabama, Arkansas, Connecticut, Delaware, Florida, Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, Massachusetts, Michigan, Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Virginia, West Virginia, and Wisconsin.

The EPA used the final CAIR policy run to estimate marginal costs of SO2 and NOx control under CAIR, and to develop projections of emissions under CAIR and emission reductions compared to the Base Case. The EPA used parsed files produced from this IPM run to analyze State level emission projections.

IPM Run ID: CAIR 2004_ Final_ DE and NJ Description: CAIR Policy Run If DE and NJ Are Required to Make Annual Reductions This run represents the CAIR requirements if EPA finalizes its proposal to require annual SO2 and NOx emission reductions in Delaware and New Jersey. This run is the same as the final CAIR policy run, CAIR 2004_ Final, except that these 2 additional States are included under the annual SO2 and NOx caps. The EPA used this run to develop projections of emissions and emission reductions if EPA finalizes its proposal to require annual SO2 and NOx reductions in Delaware and New Jersey. The EPA used parsed files produced from this IPM run to analyze State level emission projections.

IPM Run ID: CAIR 2004_ No NOx Description: CAIR SO2 Policy with Base Case NOx Policy This run uses the same SO2 policy as the initial CAIR policy run, CAIR 2004_ Analysis, but for NOx the Base Case policy is used. As with the CAIR 2004 analysis run, modeling was based on a slightly different control region than that covered by the final rule ( if EPA finalizes its proposal to require annual emission reductions in Delaware and New Jersey, then the SO2 region capped in 8 this run will be the same as that final region, except that Arkansas was included in this run but would not be in the final region). The EPA used this model run to estimate costs of the SO2 policy alone. Specifically, we compared the annual costs of the Base Case with the annual costs of this model run to get the costs of the SO2 policy alone, and we compared the annual SO2 emissions in the Base Case with the annual SO2 emissions in this model run. Using the annual costs of the proposed SO2 policy and the annual emission reductions, we calculated the estimated average costs of SO2 reductions.

IPM Run ID: CAIR 2004_ No SO2 Description: CAIR NOx Policy with Base Case SO2 Policy This IPM run used the same NOx policy as the initial CAIR policy run, CAIR 2004_ Analysis, which includes a regionwide annual NOx cap on the District of Columbia and 26 States ( the 23 States required by CAIR to make annual emission reductions plus Arkansas, Delaware, and New Jersey), and ozone season NOx caps on Connecticut and Massachusetts. Base Case SO2 policy was used for this run. As with the CAIR 2004 analysis run, modeling was based on a slightly different control region than that covered by the final rule ( if EPA finalizes its proposal to require annual emission reductions in Delaware and New Jersey, then the NOx region capped in this run will be the same as that final region with the exception of Arkansas, although this run does not include a separate nested ozone season cap on all ozone States). The EPA used this model run to estimate costs of the NOx policy alone. Specifically, we compared the annual costs of the Base Case with the annual costs of this model run to get the costs of the NOx policy alone, and we compared the annual NOx emissions in the Base Case with the annual NOx emissions in this model run. Using the annual costs of the proposed NOx policy and the annual emission reductions, we calculated the estimated average costs of NOx reductions.

In addition, we used this run to estimate the average cost of NOx reductions during the months outside of the ozone season ( non ozone season reductions). That analysis is discussed further below ( see the run ID CAIR 2004_ No SO2_ Summer NOx_ 1).

IPM Run ID: CAIR 2004_ EIA Description: CAIR Policy Using Alternate Assumptions for Natural Gas Price and Electricity Growth The EPA performed a sensitivity analysis to evaluate the effect of varying our assumptions about natural gas price and electricity growth on the projected marginal costs of CAIR. This model run is the same as the initial CAIR policy run, CAIR 2004_ Analysis, except for the different assumptions for natural gas price and electricity growth. Specifically, for this run EPA used the difference between EIA's estimates for well head natural gas prices and minemouth coal prices to establish the difference between the natural gas and coal prices for this IPM run, increasing our natural gas price assumptions to be more similar to EIA's. For electricity growth in this IPM run, we replaced EPA's assumed annual growth of 1.6% with EIA's projection of annual growth of 1.8 %. As with the CAIR 2004 analysis run, modeling was based on a slightly different control strategy than that required by the final rule, but quite similar to what the final requirements will be if EPA finalizes its proposal to require annual reductions in Delaware and New Jersey. 9 IPM Run ID: CAIR 2004_ CSP Description: Final CAIR Policy with Compliance Supplement Pool The EPA performed a sensitivity analysis to evaluate the effect of an annual NOx Compliance Supplement Pool on the projected marginal costs of NOx control of CAIR. This run is the same as the final CAIR policy run, CAIR 2004_ Final, except that an additional 200,000 tons is added to the annual NOx cap for the initial model run year. In other IPM runs in v. 2.1.9, years 2008 through 2012 are mapped to model run year 2010, however in this run, year 2008 is mapped separately to model run year 2008 and years 2009 through 2012 are mapped to model run year 2010.

IPM Run ID: CAIR 2004_ No SO2_ Summer NOx_ 1 Description: CAIR NOx Policy during Ozone Season Only in All CAIR States, with Base Case SO2 Policy In this IPM run, EPA applied ozone season NOx controls at CAIR levels in all States affected by CAIR ( not only in States that are required to make ozone season NOx reductions), and Base Case SO2 policy. Specifically, EPA applied a regionwide ozone season NOx cap on the same 26 States plus the District of Columbia as in run CAIR 2004_ No SO2 ( see above), and separate ozone season NOx caps on Connecticut and Massachusetts.

The EPA used this IPM run to estimate the average cost of NOx reductions during months outside the ozone season ( non ozone season reductions). The Agency compared the NOx emissions from this run to the NOx emissions from run CAIR 2004_ No SO2 ( which included annual NOx reductions in all affected States except Connecticut and Massachusetts, which have ozone season reductions), to get an estimate of non ozone season reductions. We also compared the total costs of the same two model runs, and used the difference in costs and the difference in emissions to estimate the average cost of NOx tons reduced during months outside of the ozone season. ( For this IPM run, EPA assumed that Rhode Island   which was not found to be a significant contributor for 8 hour ozone or PM2.5 under CAIR, but is a NOx SIP Call State   would not trade with CAIR States. This was simply an assumption for modeling purposes, it does not reflect any assumption of future policy choices.)

IPM Run ID: CAIR 2004_ No SO2_ Summer NOx_ 2 Description: CAIR NOx Policy during Ozone Season Only in 8 Hour Ozone States, with Base Case SO2 Policy The EPA used this IPM run to estimate the average and marginal costs of ozone season NOx reductions for CAIR. This run is quite similar to the run described above, with regionwide ozone season NOx controls at CAIR levels and Base Case SO2 policy. The difference between this run and the preceding run is in the region covered by the ozone season NOx caps. For the preceding run, ozone season NOx caps were applied to all States affected by CAIR, however, for this run ozone season caps were applied only to the subset of States that EPA found to be significant contributors for 8 hour ozone ( 25 States and the District of Columbia).

To estimate the average costs of ozone season NOx reductions for CAIR, EPA compared the 10 total costs of the Base Case IPM run with the total costs of this IPM run and compared the NOx emissions in the Base Case run with the NOx emissions in this run. ( For this IPM run, EPA assumed that Rhode Island   which was not found to be a significant contributor for 8 hour ozone under CAIR, but is a NOx SIP Call State   would not trade with CAIR States. This was simply an assumption for modeling purposes, it does not reflect any assumption of future policy choices.)

IPM Run ID: BART 2004_ No NOx Description: Nationwide BART SO2 Limits, with Base Case NOx Policy In this IPM run, EPA modeled the Regional Haze Requirements for Best Available Retrofit Technology ( BART) as nationwide source specific SO2 limits of 90% SO2 reduction or 0.1 lb/ mmBtu rate ( except the 5 State WRAP region for which we did not model SO2 controls beyond what is done for the WRAP cap in the base case modeling). The SO2 limits were applied to all BART eligible units of capacity greater than 100 MW. The EPA used this model run to estimate the average costs of BART SO2 controls for comparison with CAIR costs.

IPM Run ID: BART 2004_ No SO2 Description: Nationwide BART NOx Limits, with Base Case SO2 Policy In this IPM run, EPA modeled the Regional Haze Requirements for BART as a nationwide source specific NOx emission rate limit of 0.2 lb/ mmBtu NOx. The NOx limit was applied to all units with capacity greater than 25 MW. The EPA used this model run to estimate the average costs of BART NOx controls for comparison with CAIR costs.

IPM Run ID: CAIR 2004_ SCR Bypass_ NOx SIP Call Description: CAIR Policy with Cost for Gas Bypass Duct Systems on Existing SCRs The EPA used this run as a sensitivity analysis to evaluate the effect of adding a gas bypass duct system to each existing SCR installation on the costs of CAIR. In this run, the cost of a gas bypass duct system was added for pre 1994 coal units with SCR that are located in the NOx SIP Call region or OTR. ( This result is not presented in the NFR preamble section IV, but is in the RTC document.) 11 Table 1   Combustion Control Costs Used in Estimating Average Control Costs ( dollars 1/ year)

IPM Run ID 2009 / 2010 2015 Base Case 2004 $ 48,787,094 $ 48,879,415 CAIR 2004_ No NOx $ 48,787,094 $ 48,879,415 CAIR 2004_ No SO2 $ 90,952,515 $ 91,044,836 CAIR 2004_ No SO2_ Summer NOx_ 1 $ 90,952,515 $ 91,044,836 CAIR 2004_ No SO2_ Summer NOx_ 2 $ 79,044,348 $ 79,136,668 BART 2004_ No NOx $ 48,787,094 $ 48,879,415 BART 2004_ No SO2 $ 48,787,094 $ 122,104,629 1 1999$

Description of IPM Runs Used to Estimate Capacity of Control Retrofits for Feasibility Analyses The EPA used IPM to project the capacity of EGUs that would be retrofit with emission control devices for compliance with CAIR, in order to evaluate the feasibility of achieving the CAIR control levels in the available time period. The emission control devices in EPA's analysis include selective catalytic reduction ( SCR) and Flue Gas Desulfurization ( FGD). EPA provides a detailed discussion of its feasibility analyses in section IV. C in the CAIR NFR preamble. In addition, EPA provides further discussion in a TSD entitled " Boilermaker Labor and Installation Timing Analysis" that is available in the CAIR docket. The Agency used IPM to project the capacity of SCR and FGD retrofits that would occur for compliance with CAIR, as well as to project the capacity of retrofits that could occur under alternate scenarios. The IPM runs that EPA used for these analyses are described below.

IPM Run ID: EPA216_ IAQR_ 2003 Description: Policy Case for the CAIR NPR The EPA used this IPM run to project control retrofits under the conditions of the CAIR NPR. This run was described in the NPR.

IPM Run ID: CAIR 2004_ Analysis Description: CAIR 2004 Analysis Run This is the CAIR 2004 analysis run, which EPA used for several analyses for the final CAIR. See description above. 12 4 EPA used the marginal cost curve analysis solely to corroborate its findings concerning cost effectiveness of CAIR emission reductions. The marginal cost curve reflects only emissions reduction and cost information, and not other considerations. We note that it might be reasonable in a particular regulatory action to require emissions reductions past the knee of the curve to reduce overall costs of meeting the NAAQS or to achieve benefits that exceed costs. It should be noted that similar analysis for other source categories may yield different curves. IPM Run ID: CAIR 2004_ EIA Description: CAIR Policy Using Alternate Assumptions for Natural Gas Price and Electricity Growth The EPA used this run as a sensitivity analysis to evaluate the effect of varying assumptions about natural gas price and electricity growth on the capacity of control retrofits. See description of this run above.

IPM Run ID: CAIR 2004_ EIA_ SCR Costs Description: CAIR Policy Using Alternate Assumptions for Natural Gas Price, Electricity Growth, and SCR Costs The EPA used this run as a sensitivity analysis to evaluate the effect of varying assumptions about natural gas price, electricity growth, and SCR costs on the capacity of control retrofits. In this run, the natural gas price and electricity growth assumptions are the same as in run CAIR 2004_ EIA. For SCR costs in this run, EPA assumed 30% higher capital costs and fixed Operations and Maintenance costs for SCR on coal fired units, compared to the costs in EPA's other IPM runs.

IPM Run ID: CAIR 2004_ EIA_ One Phase Description: CAIR Policy Using Alternate Assumptions for Natural Gas Price and Electricity Growth, with Implementation in One Phase Starting in 2010 The EPA used this run as a sensitivity analysis to evaluate the effect of varying assumptions about natural gas price and electricity price, in addition to modifying the timing of the control requirements, on the capacity of control retrofits. In this run, the natural gas price and electricity growth assumptions are the same as in run CAIR 2004_ EIA. In addition, this run is based on a policy with one control phase instead of two phases. In this run, the CAIR second phase ( lower) regionwide SO2 and NOx emissions caps are implemented in 2010 instead of 2015.

Background on EPA's TRUM Analyses The EPA developed marginal cost curves to examine the changes in marginal costs for EGUs at varying levels of SO2 and NOx emission reductions. These curves are presented in section IV in the CAIR NFR preamble4. The Agency developed these marginal cost curves using the Technology Retrofit and Updating Model ( TRUM), a model that selects investment options and dispatches generation to meet electricity demand. For simplicity, TRUM was developed as a steady state, single region spreadsheet model supported by Visual Basic for Applications ( VBA) code. The TRUM consists of a set of sample generating units with varying characteristics. The 13 mix of generation types and sizes was chosen to mirror, in general terms, the nationwide mix of capacities. The TRUM relies on the same underlying data as IPM. For the final CAIR, EPA updated TRUM based on the IPM update ( IPM version 2.1.9).

In the CAIR NPR, the Agency also presented marginal costs curves for SO2 and NOx reductions from EGUs. When the NPR was published, EPA provided a detailed description of its use of TRUM to develop such curves in a memo to the CAIR docket. That memo, which is entitled " Analysis of the Marginal Cost of SO2 and NOx Reductions" and dated January 28, 2004, is available in the CAIR docket and also on EPA's website. For a more detailed description of EPA's use of TRUM than is provided in this TSD, refer to the January 28, 2004 memo.


[Federal Register Volume 80, Number 9 (Wednesday, January 14, 2015)]
[Notices]
[Page 1908]
[FR Doc No: 2015-00383]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

Combined Notice of Filings #1

    Take notice that the Commission received the following exempt
wholesale generator filings:

    Docket Numbers: EG15-36-000.
    Applicants: Old Mill Solar, LLC.
    Description: Self-Certification of EWG of Old Mill Solar, LLC.
    Filed Date: 1/5/15.
    Accession Number: 20150105-5185.
    Comments Due: 5 p.m. ET 1/26/15.

    Take notice that the Commission received the following electric
rate filings:

    Docket Numbers: ER14-1095-001.
    Applicants: Southern California Edison Company.
    Description: Compliance filing per 35: Compliance Filing CalWind
Revised GIA to be effective 12/15/2013.
    Filed Date: 1/6/15.
    Accession Number: 20150106-5096.
    Comments Due: 5 p.m. ET 1/27/15.

    Docket Numbers: ER14-1969-004.
    Applicants: Public Service Company of Colorado.
    Description: Compliance filing per 35: 2015-1-5_PSCo Wind Int Comp
Filing_ER14-1969 to be effective 1/1/2015.
    Filed Date: 1/5/15.
    Accession Number: 20150105-5147.
    Comments Due: 5 p.m. ET 1/26/15.

    Docket Numbers: ER15-822-000.
    Applicants: Southern California Edison Company.
    Description: Sec.  205(d) rate filing per 35.13(a)(2)(iii): Service
Agmt for Wholesale Distribution Service with Morgan Lancaster I, LLC to
be effective 3/8/2015.
    Filed Date: 1/6/15.
    Accession Number: 20150106-5002.
    Comments Due: 5 p.m. ET 1/27/15.

    Docket Numbers: ER15-823-000.
    Applicants: Southern California Edison Company.
    Description: Sec.  205(d) rate filing per 35.13(a)(2)(iii): Service
Agmts Wholesale Distribution Service--Summer Solar E2, F2, G2, H2 to be
effective 3/8/2015.
    Filed Date: 1/6/15.
    Accession Number: 20150106-5003.
    Comments Due: 5 p.m. ET 1/27/15.

    Docket Numbers: ER15-824-000.
    Applicants: Midcontinent Independent System Operator, Inc.
    Description: Sec.  205(d) rate filing per 35.13(a)(2)(iii): 2015-
01-06_SA 2694_ITC-Oregon Clean Energy Amended Y1-069 to be effective 1/
7/2015.
    Filed Date: 1/6/15.
    Accession Number: 20150106-5047.
    Comments Due: 5 p.m. ET 1/27/15.

    Take notice that the Commission received the following public
utility holding company filings:

    Docket Numbers: PH15-6-000.
    Applicants: Sempra Energy.
    Description: Sempra Energy submits FERC 65-B Waiver Notice of
Change in Facts.
    Filed Date: 1/6/15.
    Accession Number: 20150106-5118.
    Comments Due: 5 p.m. ET 1/27/15.

    The filings are accessible in the Commission's eLibrary system by
clicking on the links or querying the docket number.
    Any person desiring to intervene or protest in any of the above
proceedings must file in accordance with Rules 211 and 214 of the
Commission's Regulations (18 CFR 385.211 and 385.214) on or before 5:00
p.m. Eastern time on the specified comment date. Protests may be
considered, but intervention is necessary to become a party to the
proceeding.
    eFiling is encouraged. More detailed information relating to filing
requirements, interventions, protests, service, and qualifying
facilities filings can be found at: http://www.ferc.gov/docs-filing/efiling/filing-req.pdf. For other information, call<PHONE_NUMBER>
(toll free). For TTY, call<PHONE_NUMBER>.

    Dated: January 6, 2015.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2015-00383 Filed 1-13-15; 8:45 am]
BILLING CODE 6717-01-P