[Federal Register Volume 86, Number 228 (Wednesday, December 1, 2021)]
[Rules and Regulations]
[Pages 68107-68109]
[FR Doc No: 2021-26109]

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DEPARTMENT OF TRANSPORTATION

Federal Aviation Administration

14 CFR Part 39

[Docket No. FAA-2021-0656; Project Identifier MCAI-2021-00394-T;
Amendment 39-21800; AD 2021-23-02]
RIN 2120-AA64

Airworthiness Directives; De Havilland Aircraft of Canada Limited
(Type Certificate Previously Held by Bombardier, Inc.) Airplanes

AGENCY: Federal Aviation Administration (FAA), Department of
Transportation (DOT).

ACTION: Final rule.

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SUMMARY: The FAA is adopting a new airworthiness directive (AD) for
certain De Havilland Aircraft of Canada Limited Model DHC-8-401 and -
402 airplanes. This AD was prompted by reports of loss of hydraulic
fluid and annunciation of the check fire detect light. This AD requires
doing a detailed visual inspection for chafing and proper clearance of
the left-hand (LH) and right-hand (RH) main landing gear (MLG) primary
zone advanced pneumatic detector (APD) sensing lines, the hydraulic
tube assemblies, and the surrounding structure, and doing all
applicable corrective action. The FAA is issuing this AD to address the
unsafe condition on these products.

DATES: This AD is effective January 5, 2022.
    The Director of the Federal Register approved the incorporation by
reference of a certain publication listed in this AD as of January 5,
2022.

ADDRESSES: For service information identified in this final rule,
contact De Havilland Aircraft of Canada Limited, Q-Series Technical
Help Desk, 123 Garratt Boulevard, Toronto, Ontario M3K 1Y5, Canada;
telephone<PHONE_NUMBER>; fax<PHONE_NUMBER>; email [email protected];
internet https://dehavilland.com. You may view this service information
at the FAA, Airworthiness Products Section, Operational Safety Branch,
2200 South 216th St., Des Moines, WA. For information on the
availability of this material at the FAA, call<PHONE_NUMBER>. It is also
available on the internet at https://www.regulations.gov by searching
for and locating Docket No. FAA-2021-0656.

Examining the AD Docket

    You may examine the AD docket on the internet at https://www.regulations.gov by searching for and locating Docket No. FAA-2021-
0656; or in person at Docket Operations between 9 a.m. and 5 p.m.,
Monday through Friday, except Federal holidays. The AD docket contains
this final rule, any comments received, and other information. The
address for Docket Operations is U.S. Department of Transportation,
Docket Operations, M-30, West Building Ground Floor, Room W12-140, 1200
New Jersey Avenue SE, Washington, DC 20590.

FOR FURTHER INFORMATION CONTACT: Chirayu Gupta, Aerospace Engineer,
Mechanical Systems and Administrative Services Section, FAA, New York
ACO Branch, 1600 Stewart Avenue, Suite 410, Westbury, NY 11590;
telephone<PHONE_NUMBER>; fax<PHONE_NUMBER>; email [email protected].

SUPPLEMENTARY INFORMATION:

Background

    Transport Canada Civil Aviation (TCCA), which is the aviation
authority for Canada, has issued TCCA AD CF-2021-12, dated April 14,
2021 (also referred to as the Mandatory Continuing Airworthiness
Information, or the MCAI), to correct an unsafe condition for certain
De Havilland Aircraft of Canada Limited Model DHC-8-401 and -402
airplanes. You may examine the MCAI in the AD docket on the internet at
https://www.regulations.gov by searching for and locating Docket No.
FAA-2021-0656.
    The FAA issued a notice of proposed rulemaking (NPRM) to amend 14
CFR part 39 by adding an AD that would apply to certain De Havilland
Aircraft of Canada Limited Model DHC-8-401 and -402 airplanes. The NPRM
published in the Federal Register on August 12, 2021 (86 FR 44324). The
NPRM was prompted by reports of loss of hydraulic fluid and
annunciation of the check fire detect light. The NPRM proposed to
require doing a detailed visual inspection for chafing and proper
clearance of the LH and RH MLG primary zone APD sensing lines, the
hydraulic tube assemblies, and the surrounding structure, and doing all
applicable corrective actions. The FAA is issuing this AD to address
insufficient separation between the APD sensing line and surrounding
components, which could lead to a hydraulic leak, loss of hydraulic
systems, and loss of fire detection in the MLG primary zone should
prolonged contact occur. See the MCAI for additional background
information.

Comments

    The FAA gave the public the opportunity to participate in
developing this final rule. The FAA has considered the comment
received. The Air Line Pilots Association, International (ALPA) stated
that it supports the NPRM.

Conclusion

    The FAA reviewed the relevant data, considered the comment
received, and determined that air safety and the public interest
require adopting this final rule as proposed, except for minor
editorial changes. The FAA has determined that these minor changes:
     Are consistent with the intent that was proposed in the
NPRM for addressing the unsafe condition; and
     Do not add any additional burden upon the public than was
already proposed in the NPRM.

Related Service Information Under 1 CFR Part 51

    De Havilland Aircraft of Canada Limited has issued Service Bulletin
84-26-20, Revision A, dated March 9, 2021. This service information
describes procedures for doing a detailed visual inspection for chafing
and proper clearance of the LH and RH MLG primary zone APD sensing
lines, the hydraulic tube assemblies and the surrounding structure, and
doing all applicable corrective actions. Corrective actions include
repair and replacement of the APD sensing line and the hydraulic tube
assembly.
    This service information is reasonably available because the
interested parties have access to it through their normal course of
business or by the means identified in the ADDRESSES section.

Costs of Compliance

    The FAA estimates that this AD affects 54 airplanes of U.S.
registry. The FAA estimates the following costs to comply with this AD:

                                      Estimated Costs for Required Actions
----------------------------------------------------------------------------------------------------------------
                                                                                Cost per       Cost on U.S.
                          Labor cost                              Parts cost        product         operators
----------------------------------------------------------------------------------------------------------------
5 work-hours x $85 per hour = $425...........................              $0             $425          $22,950
----------------------------------------------------------------------------------------------------------------

    The FAA estimates the following costs to do any necessary on-
condition actions that would be required based on the results of any
required actions. The FAA has no way of determining the number of
aircraft that might need these on-condition actions:

                 Estimated Costs of On-Condition Actions
------------------------------------------------------------------------
           Labor cost                 Parts cost       Cost per product
------------------------------------------------------------------------
Up to 7 work-hours x $85 per      Up to $12,643.....  Up to $13,238.
 hour = Up to $595.
------------------------------------------------------------------------

Authority for This Rulemaking

    Title 49 of the United States Code specifies the FAA's authority to
issue rules on aviation safety. Subtitle I, section 106, describes the
authority of the FAA Administrator. Subtitle VII: Aviation Programs,
describes in more detail the scope of the Agency's authority.
    The FAA is issuing this rulemaking under the authority described in
Subtitle VII, Part A, Subpart III, Section 44701: General requirements.
Under that section, Congress charges the FAA with promoting safe flight
of civil aircraft in air commerce by prescribing regulations for
practices, methods, and procedures the Administrator finds necessary
for safety in air commerce. This regulation is within the scope of that
authority because it addresses an unsafe condition that is likely to
exist or develop on products identified in this rulemaking action.

Regulatory Findings

    This AD will not have federalism implications under Executive Order
13132. This AD will not have a substantial direct effect on the States,
on the relationship between the national government and the States, or
on the distribution of power and responsibilities among the various
levels of government.
    For the reasons discussed above, I certify that this AD:
    (1) Is not a ``significant regulatory action'' under Executive
Order 12866,
    (2) Will not affect intrastate aviation in Alaska, and
    (3) Will not have a significant economic impact, positive or
negative, on a substantial number of small entities under the criteria
of the Regulatory Flexibility Act.

List of Subjects in 14 CFR Part 39

    Air transportation, Aircraft, Aviation safety, Incorporation by
reference, Safety.

Adoption of the Amendment

    Accordingly, under the authority delegated to me by the
Administrator, the FAA amends 14 CFR part 39 as follows:

PART 39--AIRWORTHINESS DIRECTIVES

0
1. The authority citation for part 39 continues to read as follows:

    Authority:  49 U.S.C. 106(g), 40113, 44701.

Sec.  39.13  [Amended]

0
2. The FAA amends Sec.  39.13 by adding the following new airworthiness
directive:

2021-23-02 De Havilland Aircraft of Canada Limited (Type Certificate
Previously Held by Bombardier, Inc.): Amendment 39-21800; Docket No.
FAA-2021-0656; Project Identifier MCAI-2021-00394-T.

(a) Effective Date

    This airworthiness directive (AD) is effective January 5, 2022.

(b) Affected ADs

    None.

(c) Applicability

    This AD applies to De Havilland Aircraft of Canada Limited Model
DHC-8-401 and -402 airplanes, certificated in any category, serial
numbers 4001 and 4003 through 4614 inclusive.

(d) Subject

    Air Transport Association (ATA) of America Code 26, Fire
protection.

(e) Unsafe Condition

    This AD was prompted by reports of loss of hydraulic fluid and
annunciation of the check fire detect light. The FAA is issuing this
AD to address insufficient separation between the advanced pneumatic
detector (APD) sensing line and surrounding components, which could
lead to a hydraulic leak, loss of hydraulic systems and loss of fire
detection in the main landing gear (MLG) primary zone should
prolonged contact occur.

(f) Compliance

    Comply with this AD within the compliance times specified,
unless already done.

(g) Inspection and Corrective Actions

    Within 48 months or 8,000 flight hours, whichever occurs first
after the effective date of this AD: Do a detailed visual inspection
for chafing and proper clearance of the left- and right-hand MLG
primary zone APD sensing lines, the hydraulic tube assemblies and
the surrounding structure, and do all applicable corrective actions,
in accordance with paragraph 3.B. of the Accomplishment Instructions
of De Havilland Aircraft of Canada Limited Service Bulletin 84-26-
20, Revision A, dated March 9, 2021. Do all applicable corrective
actions before further flight.

(h) Credit for Previous Actions

    This paragraph provides credit for actions required by paragraph
(g) of this AD, if those actions were performed before the effective
date of this AD using De Havilland Aircraft of Canada Limited
Service Bulletin 84-26-20, dated October 21, 2020.

(i) Other FAA AD Provisions

    The following provisions also apply to this AD:
    (1) Alternative Methods of Compliance (AMOCs): The Manager, New
York ACO Branch, FAA, has the authority to approve AMOCs for this
AD, if requested using the procedures found in 14 CFR 39.19. In
accordance with 14 CFR 39.19, send your request to your principal
inspector or responsible Flight Standards Office, as appropriate. If
sending information directly to the manager of the certification
office, send it to ATTN: Program Manager, Continuing Operational
Safety, FAA, New York ACO Branch, 1600 Stewart Avenue, Suite 410,
Westbury, NY 11590; telephone<PHONE_NUMBER>; fax<PHONE_NUMBER>. Before

using any approved AMOC, notify your appropriate principal
inspector, or lacking a principal inspector, the manager of the
responsible Flight Standards Office.
    (2) Contacting the Manufacturer: For any requirement in this AD
to obtain instructions from a manufacturer, the instructions must be
accomplished using a method approved by the Manager, New York ACO
Branch, FAA; or Transport Canada Civil Aviation (TCCA); or De
Havilland Aircraft of Canada Limited's TCCA Design Approval
Organization (DAO). If approved by the DAO, the approval must
include the DAO-authorized signature.

(j) Related Information

    (1) Refer to Mandatory Continuing Airworthiness Information
(MCAI) TCCA AD CF-2021-12, dated April 14, 2021, for related
information. This MCAI may be found in the AD docket on the internet
at https://www.regulations.gov by searching for and locating Docket
No. FAA-2021-0656.
    (2) For more information about this AD, contact Chirayu Gupta,
Aerospace Engineer, Mechanical Systems and Administrative Services
Section, FAA, New York ACO Branch, 1600 Stewart Avenue, Suite 410,
Westbury, NY 11590; telephone<PHONE_NUMBER>; fax<PHONE_NUMBER>; email
[email protected].
    (3) Service information identified in this AD that is not
incorporated by reference is available at the addresses specified in
paragraphs (k)(3) and (4) of this AD.

(k) Material Incorporated by Reference

    (1) The Director of the Federal Register approved the
incorporation by reference (IBR) of the service information listed
in this paragraph under 5 U.S.C. 552(a) and 1 CFR part 51.
    (2) You must use this service information as applicable to do
the actions required by this AD, unless this AD specifies otherwise.
    (i) De Havilland Aircraft of Canada Limited Service Bulletin 84-
26-20, Revision A, dated March 9, 2021.
    (ii) [Reserved]
    (3) For service information identified in this AD, contact De
Havilland Aircraft of Canada Limited, Q-Series Technical Help Desk,
123 Garratt Boulevard, Toronto, Ontario M3K 1Y5, Canada; telephone
416-375-4000; fax<PHONE_NUMBER>; email [email protected]; internet
https://dehavilland.com.
    (4) You may view this service information at the FAA,
Airworthiness Products Section, Operational Safety Branch, 2200
South 216th St., Des Moines, WA. For information on the availability
of this material at the FAA, call<PHONE_NUMBER>.
    (5) You may view this service information that is incorporated
by reference at the National Archives and Records Administration
(NARA). For information on the availability of this material at
NARA, email [email protected], or go to: https://www.archives.gov/federal-register/cfr/ibr-locations.html.

    Issued on October 26, 2021.
Lance T. Gant,
Director, Compliance & Airworthiness Division, Aircraft Certification
Service.
[FR Doc. 2021-26109 Filed 11-30-21; 8:45 am]
BILLING CODE 4910-13-P


10 G Street, N. E. Suite 700 Washington, D. C. 20002 September 28, 2005 Robert Wayland U. S. Environmental Protection Agency Mail Code: C439 01 Research Triangle Park, NC 27711 Dear Dr. Wayland:

In an August 2, 2005 conference call between the Interstate Natural Gas Association of America ( INGAA) and EPA, the status of the Subpart KKKK Turbine NSPS proposal was discussed. One topic discussed was the inherently low sulfur levels in natural gas, and the INGAA position that the Subpart KKKK proposal should be revised or clarified to avoid unnecessary sulfur monitoring. INGAA noted that the 2004 revisions to the existing Turbine NSPS, Subpart GG, included positive changes that eliminated unnecessary sulfur monitoring. As detailed in our April 2005 comments on the proposed standard, INGAA is concerned that Subpart KKKK would reinstate unnecessary sampling requirements for affected units. INGAA has provided a summary of analysis results from previous Subpart GG sampling that indicates natural gas sulfur levels far below the proposed limit in Subpart KKKK   even when the sulfur requirement in the natural gas tariff sheet ( e. g., 20 grains total sulfur per 100 SCF) is marginally higher than the proposed sulfur limit in Subpart KKKK.

As an action item from the conference call, INGAA was asked to provide example rule language to address sulfur monitoring. As discussed in the call, a concept of interest for low sulfur natural gas is an approach with decreasing frequency and cessation of sampling requirements when the natural gas is shown to contain total sulfur well below the 500 ppmw proposed limit ( e. g., less than 10% of the limit).

INGAA offers two options below for revised rule language that would minimize unnecessary sulfur monitoring for natural gas fired turbines under Subpart KKKK. The first option includes reduced frequency and eventual elimination of monitoring when sulfur analysis for gas is shown to be much less than tariff levels and the 500 ppmw proposed limit. In addition, this option includes text to allow representative analysis that has been completed under an existing custom monitoring schedule to serve as the basis to validate low sulfur levels and eliminate the need for additional testing for a Subpart KKKK unit. The second option considers another approach discussed in the August 2 call, and is based on providing an alternative sulfur limit for natural gas commensurate with the common tariff level for interstate pipelines. INGAA still believes that this is a viable option and provides proposed language following such an approach as a second option. Further discussion and the INGAA proposed text for the two options follow. Proposed revisions to the relevant Subpart KKKK text is shown with additions underlined and strikethrough used for deletions.

Option 1: This approach retains the fuel sulfur limits in the proposal. Proposed new text addresses natural gas with a tariff sheet/ transportation contract specification of 20 grains per 100 SCF or less, and defines fuel sulfur testing with a sample frequency that decreases if the measured value is shown to be significantly less than the tariff specification and Subpart KKKK sulfur limit. Testing discontinues if multiple measurements indicate a sulfur level less than 10% of the sulfur limit. Note that INGAA believes that the tariff provides an assurance of continuity in fuel sulfur content over time. However, as an alternative, this provision could be " fuel neutral" and the proposed fuel analysis schedule proposed below for natural gas could be allowed for any fuel under Subpart KKKK that is measured at less than 10% of the standard, with some assurance that fuel sulfur content remains consistent over time. The proposed language follows:

§ 60.4365 How can I be exempted from monitoring the total sulfur content of the fuel? You may elect not to monitor the total sulfur content of the fuel combusted in the turbine, if the fuel is demonstrated not to exceed 300 ppmw total sulfur. You must use one of the following sources of information to make the required demonstration: ( a) The fuel quality characteristics in a current, valid purchase contract, tariff sheet or transportation contract for the fuel, specifying that the maximum total sulfur content of the fuel is 300 ppmw or less; or ( b) Representative fuel sampling data which show that the sulfur content of the fuel does not exceed 300 ppmw. At a minimum, the amount of fuel sampling data specified in section <IP_ADDRESS> or <IP_ADDRESS> of appendix D to part 75 of this chapter is required.; or ( c) For natural gas as defined in § 60.4420 with a total sulfur requirement in a tariff sheet or contract specification not to exceed 20 grains per 100 standard cubic feet, sampling following the criteria identified in § 60.4370( c).

§ 60.4370 How often must I determine the sulfur content of the fuel? The frequency of determining the sulfur content of the fuel must be as follows: ( a) Fuel oil. For fuel oil, use one of the total sulfur sampling options and the associated sampling frequency described in sections 2.2.3, <IP_ADDRESS>, <IP_ADDRESS>, and <IP_ADDRESS> of appendix D to part 75 of this chapter ( i. e., flow proportional sampling, daily sampling, sampling from the unit's storage tank after each addition of fuel to the tank, or sampling each delivery prior to combining it with fuel oil already in the intended storage tank). ( b) Gaseous fuel. If you elect not to demonstrate sulfur content using options in § 60.4365, and the fuel is supplied without intermediate bulk storage, the sulfur content value of the gaseous fuel must be determined and recorded once per unit operating day. ( c) Natural gas. Conduct quarterly testing to determine the sulfur content of the fuel. If any quarterly test indicates total sulfur content less than 50 ppmw ( 10% of the 500 ppmw sulfur limit), then the test frequency can be reduced to annually. If two consecutive annual tests indicate total sulfur content less than 50 ppmw, no subsequent fuel sampling and analysis is required. The quarterly test that triggers an annual frequency serves as the first of two annual tests to fulfill this requirement. ( i) If within the previous five years, representative fuel sampling has been conducted on the natural gas pipeline under a custom monitoring schedule, records of that analysis can be used to fulfill the requirements of § 60.4370( c). If these results indicate total sulfur less than 50 ppmw, then no additional fuel sulfur analysis is required.

Option 2: This approach provides alternative sulfur criteria for units that fire natural gas, with a separate sulfur limit based on fuel that meets the Subpart KKKK definition of natural gas and includes a tariff limit of 20 grains per 100 SCF or less. Revisions are required to § 60.4330( b) along with addition of a new section ( c). Proposed text for the tariff based exemption in § 60.4365 is also provided. The proposed language follows:

§ 60.4330 What emission limits must I meet for sulfur dioxide ( SO2)? You must comply with one or the other of the following conditions: ( a) You must not cause to be discharged into the atmosphere from the subject stationary combustion turbine any gases which contain SO2 in excess of 73 nanograms per Joule ( ng/ J) ( 0.58 pounds per megawatt hour ( lb/ MW  hr)), or ( b) You must not burn in the subject stationary combustion turbine any liquid fuel or gaseous fuel other than natural gas which contains total sulfur in excess of 0.05 percent by weight ( 500 parts per million by weight ( ppmw))., or ( c) For a subject stationary combustion turbine burning natural gas as defined in § 60.4420, you must not burn natural gas with total sulfur content in excess of 20 grains per 100 standard cubic feet based on a valid tariff sheet or transportation contract.

§ 60.4365 How can I be exempted from monitoring the total sulfur content of the fuel? You may elect not to monitor the total sulfur content of the fuel combusted in the turbine, if the fuel is natural gas with a total sulfur level not to exceed 20 grains per 100 standard cubic feet or other fuel demonstrated not to exceed 300 ppmw total sulfur. You must use one of the following sources of information to make the required demonstration: ( a) The fuel quality characteristics in a current, valid purchase contract, tariff sheet or transportation contract for the fuel, specifying that the maximum total sulfur content of natural gas does not exceed 20 grains per 100 standard cubic feet or the total sulfur content of other fuels is 300 ppmw or less; or ( b) Representative fuel sampling data which show that the sulfur content of the fuel does not exceed 300 ppmw. At a minimum, the amount of fuel sampling data specified in section <IP_ADDRESS> or <IP_ADDRESS> of appendix D to part 75 of this chapter is required.

INGAA appreciates your consideration of this issue. If you have any questions or require clarification or additional input on the sulfur monitoring language proposed, please contact me at 202 216 5935.

Sincerely,

Lisa S. Beal Director, Environment and Construction Policy Interstate Natural Gas Association of America cc ( by email): Jaime Pagan, U. S. EPA Sims Roy, U. S. EPA


[Federal Register Volume 87, Number 33 (Thursday, February 17, 2022)]
[Notices]
[Pages 9044-9046]
[FR Doc No: 2022-03424]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. CP22-44-000]

Equitrans, L.P.; Notice of Application and Establishing
Intervention Deadline

    Take notice that on January 28, 2022, Equitrans, L.P. (Equitrans),
2200 Energy Drive, Canonsburg, Pennsylvania 15317, filed an application
under sections 7(c) of the Natural Gas Act (NGA), and Part 157 of the
Commission's regulations requesting that the Commission authorize its
Ohio Valley Connector Expansion Project (Project), which will provide
up to 350,000 dekatherms per day (Dth/d) of incremental firm
deliverability on its Mainline System and new transportation paths.
This Project is an expansion of the Equitrans' Ohio Valley Connector
Project which was approved in Docket No. CP15-41-000 and which is
already in service. Specifically, the Project will provide additional
pipeline delivery capabilities to existing interconnects with Rockies
Express Pipeline and Rover Pipeline LLC, all as more fully set forth in
the application which is on file with the Commission and open for
public inspection.
    Specifically, Specifically, Equitrans proposes to acquire the
Cygrymus Compressor Station in Greene County, Pennsylvania and to
construct and operate: (i) Two Taurus 70 turbines at the Cygrymus
Compressor Station; (ii) one additional Mars 100 compressor unit at the
existing Corona Compressor Station Wetzel County, West Virginia; (iii)
one additional Titan 130 compressor unit at the existing Plasma
Compressor Station in Monroe County, Ohio; (iv) approximately 5.5 miles
of pipeline in different locations related to the compressor stations;
(v) one deep anode groundbed and rectifier for cathodic protection in
Greene County, Pennsylvania; and (vi) ancillary facilities. Equitrans
proposes to use the applicable Ohio Valley Connector System rates as
the maximum recourse rates for service on the project and to roll-in
the costs of the project into its general system rates in its next NGA
Section 4 general rate proceeding. The project shippers elected to pay
negotiated rates. The estimated cost of the project is $167,510,106.
    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 the Commission's Home Page (http://ferc.gov) using the
``eLibrary'' link. Enter the docket number excluding the last three
digits in the docket number field to access the document. 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 the Federal Energy
Regulatory Commission at [email protected] or call toll-free,
(886) 208-3676 or TYY,<PHONE_NUMBER>.
    Any questions regarding the proposed project should be directed to
Matthew Eggerding, Assistant General Counsel, at Equitrans, L.P., 2200
Energy Drive, Canonsburg, PA 15317; by phone at<PHONE_NUMBER>; or by
email to [email protected].
    Pursuant to Section 157.9 of the Commission's Rules of Practice and
Procedure,\1\ within 90 days of this Notice the Commission staff will
either: Complete its environmental review and place it into the
Commission's public record (eLibrary) for this proceeding; or issue a
Notice of Schedule for Environmental Review. If a Notice of Schedule
for Environmental Review is issued, it will indicate, among other

milestones, the anticipated date for the Commission staff's issuance of
the final environmental impact statement (FEIS) or environmental
assessment (EA) for this proposal. The filing of an EA in the
Commission's public record for this proceeding or the issuance of a
Notice of Schedule for Environmental Review will serve to notify
federal and state agencies of the timing for the completion of all
necessary reviews, and the subsequent need to complete all federal
authorizations within 90 days of the date of issuance of the Commission
staff's FEIS or EA.
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    \1\ 18 CFR (Code of Federal Regulations) 157.9.
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Public Participation

    There are two ways to become involved in the Commission's review of
this project: You can file comments on the project, and you can file a
motion to intervene in the proceeding. There is no fee or cost for
filing comments or intervening. The deadline for filing a motion to
intervene is 5:00 p.m. Eastern Time on March 4, 2022.

Comments

    Any person wishing to comment on the project may do so. Comments
may include statements of support or objections to the project as a
whole or specific aspects of the project. The more specific your
comments, the more useful they will be. To ensure that your comments
are timely and properly recorded, please submit your comments on or
before March 4, 2022.
    There are three methods you can use to submit your comments to the
Commission. In all instances, please reference the Project docket
number CP22-44-000 in your submission.
    (1) You may file your comments electronically by using the eComment
feature, which is located on the Commission's website at www.ferc.gov
under the link to Documents and Filings. Using eComment is an easy
method for interested persons to submit brief, text-only comments on a
project;
    (2) You may file your comments electronically by using the eFiling
feature, which is located on the Commission's website (www.ferc.gov)
under the link to Documents and Filings. 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; first select ``General'' and then select ``Comment on a
Filing''; or
    (3) You may file a paper copy of your comments by mailing them to
the following address below.\2\ Your written comments must reference
the Project docket number (CP22-44-000).
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    \2\ Hand delivered submissions in docketed proceedings should be
delivered to Health and Human Services, 12225 Wilkins Avenue,
Rockville, Maryland 20852.
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    Kimberly D. Bose, Secretary, Federal Energy Regulatory Commission,
888 First Street NE, Washington, DC 20426.
    The Commission encourages electronic filing of comments (options 1
and 2 above) and has eFiling staff available to assist you at (202)
502-8258 or [email protected]
    Persons who comment on the environmental review of this project
will be placed on the Commission's environmental mailing list, and will
receive notification when the environmental documents (EA or EIS) are
issued for this project and will be notified of meetings associated
with the Commission's environmental review process.
    The Commission considers all comments received about the project in
determining the appropriate action to be taken. However, the filing of
a comment alone will not serve to make the filer a party to the
proceeding. To become a party, you must intervene in the proceeding.
For instructions on how to intervene, see below.

Interventions

    Any person, which includes individuals, organizations, businesses,
municipalities, and other entities,\3\ has the option to file a motion
to intervene in this proceeding. Only intervenors have the right to
request rehearing of Commission orders issued in this proceeding and to
subsequently challenge the Commission's orders in the U.S. Circuit
Courts of Appeal.
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    \3\ 18 CFR 385.102(d).
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    To intervene, you must submit a motion to intervene to the
Commission in accordance with Rule 214 of the Commission's Rules of
Practice and Procedure \4\ and the regulations under the NGA \5\ by the
intervention deadline for the project, which is March 4, 2022. As
described further in Rule 214, your motion to intervene must state, to
the extent known, your position regarding the proceeding, as well as
your interest in the proceeding. For an individual, this could include
your status as a landowner, ratepayer, resident of an impacted
community, or recreationist. You do not need to have property directly
impacted by the project in order to intervene. For more information
about motions to intervene, refer to the FERC website at https://www.ferc.gov/resources/guides/how-to/intervene.asp.
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    \4\ 18 CFR 385.214.
    \5\ 18 CFR 157.10.
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    There are two ways to submit your motion to intervene. In both
instances, please reference the Project docket number CP22-44-000 in
your submission.
    (1) You may file your motion to intervene by using the Commission's
eFiling feature, which is located on the Commission's website
(www.ferc.gov) under the link to Documents and Filings. 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; first select
``General'' and then select ``Intervention.'' The eFiling feature
includes a document-less intervention option; for more information,
visit https://www.ferc.gov/docs-filing/efiling/document-less-intervention.pdf.; or
    (2) You can file a paper copy of your motion to intervene, along
with three copies, by mailing the documents to the address below.\6\
Your motion to intervene must reference the Project docket number CP22-
44-000.
---------------------------------------------------------------------------

    \6\ Hand delivered submissions in docketed proceedings should be
delivered to Health and Human Services, 12225 Wilkins Avenue,
Rockville, Maryland 20852.
---------------------------------------------------------------------------

    Kimberly D. Bose, Secretary, Federal Energy Regulatory Commission,
888 First Street NE, Washington, DC 20426.
    The Commission encourages electronic filing of motions to intervene
(option 1 above) and has eFiling staff available to assist you at (202)
502-8258 or [email protected]
    Motions to intervene must be served on the applicant either by mail
or email at: Matthew Eggerding, Assistant General Counsel, at
Equitrans, L.P., 2200 Energy Drive, Canonsburg, PA 15317; by phone at
(412) 553-5786; or by email to [email protected]. Any
subsequent submissions by an intervenor must be served on the applicant
and all other parties to the proceeding. Contact information for
parties can be downloaded from the service list at the eService link on
FERC Online. Service can be via email with a link to the document.
    All timely, unopposed \7\ motions to intervene are automatically
granted by operation of Rule 214(c)(1).\8\ Motions to intervene that
are filed after the intervention deadline are untimely, and may be
denied. Any late-filed motion to intervene must show good cause for
being late and must explain why the time limitation should be waived
and

provide justification by reference to factors set forth in Rule 214(d)
of the Commission's Rules and Regulations.\9\ A person obtaining party
status will be placed on the service list maintained by the Secretary
of the Commission and will receive copies (paper or electronic) of all
documents filed by the applicant and by all other parties.
---------------------------------------------------------------------------

    \7\ The applicant has 15 days from the submittal of a motion to
intervene to file a written objection to the intervention.
    \8\ 18 CFR 385.214(c)(1).
    \9\ 18 CFR 385.214(b)(3) and (d).
---------------------------------------------------------------------------

Tracking the Proceeding

    Throughout the proceeding, additional information about the project
will be available from the Commission's Office of External Affairs, at
(866) 208-FERC, or on the FERC website at http://www.ferc.gov using the
``eLibrary'' link as described above. The eLibrary link also provides
access to the texts of all formal documents issued by the Commission,
such as orders, notices, and rulemakings.
    In addition, the Commission offers a free service called
eSubscription which allows you to keep track of all formal issuances
and submittals in specific dockets. This can reduce the amount of time
you spend researching proceedings by automatically providing you with
notification of these filings, document summaries, and direct links to
the documents. For more information and to register, go to
www.ferc.gov/docs-filing/esubscription.asp.
    Intervention Deadline: 5:00 p.m. Eastern Time on March 4, 2022.

    Dated: February 11, 2022.
Kimberly D. Bose,
Secretary.
[FR Doc. 2022-03424 Filed 2-16-22; 8:45 am]
BILLING CODE 6717-01-P


[Federal Register: July 12, 2007 (Volume 72, Number 133)]
[Notices]
[Page 38076-38077]
[DOCID:fr12jy07-55]

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

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[P-2175-014]

Southern California Edison Company; Notice of Application
Accepted for Filing and Soliciting Motions To Intervene and Protests

July 5, 2007.
    Take notice that the following hydroelectric application has been
filed with the Commission and is available for public inspection.
    a. Type of Application: New License for Major Project-Existing Dam.
    b. Project No.: P-2175-014.
    c. Date Filed: February 23, 2007.
    d. Applicant: Southern California Edison Company.
    e. Name of Project: Big Creek Nos. 1 and 2 Hydroelectric Power
Project.
    f. Location: In Fresno County, California, and within the Sierra
National Forest. The project is situated along Big Creek, a tributary
to the San Joaquin River. The project affects 1,877.96 acres of federal
land administered by the Sierra National Forest.
    g. Filed Pursuant to: Federal Power Act 16 U.S.C. 791 (a)-825(r).
    h. Applicant Contact: Russ W. Krieger, Vice President, Power
Production, Southern California Edison Company, 300 North Lone Hill
Ave., San Dimas, California 91773. Phone:<PHONE_NUMBER>.
    i. FERC Contact: Jim Fargo,<PHONE_NUMBER>, or e-mail:
<EMAIL_ADDRESS>
    j. Deadline for filing motions to intervene and protests: 60 days
from the issuance date of this notice.
    All documents (original and eight copies) should be filed with:
Kimberly D. Bose, Secretary, Federal Energy Regulatory Commission, 888
First Street, NE., Washington, DC 20426.
    The Commission's Rules of Practice require all intervenors filing
documents with the Commission to serve a copy of that document on each
person on the official service list for the project. Further, if an
intervenor files comments or documents with the Commission relating to
the merits of an issue that may affect the responsibilities of a
particular resource agency, they must also serve a copy of the document
on that resource agency.
    Motions to intervene and protests may be filed electronically via
the Internet in lieu of paper. The Commission strongly encourages
electronic filings. See 18 CFR 385.2001(a)(1)(iii) and the instructions
on the Commission's Web site (http://www.ferc.gov) under the ``e-

Filing'' link.
    k. This application has been accepted, but is not ready for
environmental analysis at this time.
    l. Description of Project: The existing Big Creek Nos. 1 and 2
Hydroelectric Power Project consists of two powerhouses, four major
dams forming one major reservoir, one moderate dam and impoundment,
three small diversions, and three water conveyance systems. The project
would have an average annual generation of 657,072 megawatt-hours.
     Powerhouses (i) Powerhouse No. 1 with four turbine/
generator units and a total dependable operating capacity of about 82.9
MW; and (ii) Powerhouse No. 2, with four turbine/generator units and a
total dependable operating capacity of about 67.1 MW.
     Major dams and reservoirs (i) Dams 1, 2, 3, and 3a, which
form Huntington Lake, with a capacity of about 89,166 ac-ft, at an
elevation of about 6,950 ft above mean sea level (msl).
     Moderate dam (i) Dam 4, which forms Dam 4 Impoundment
(Powerhouse 2 Forebay), with a capacity of about 60 ac-ft, at an
elevation of about 4,810 ft above msl.
     Small diversions (i) Balsam Creek Diversion, with a usable
capacity of less than 1 ac-ft, at an elevation of about 4,880 ft above
msl; (ii) Ely Creek Diversion, with a usable capacity of less

than 1 ac-ft, at an elevation of about 4,844 ft above msl; and (iii)
Adit 8 Diversion, with a usable capacity of less than 1 ac-ft, at an
elevation of about 4,825 ft above msl.
     Water conveyance systems (i) Tunnel No. 1, about 2 miles
long, conveys water from Huntington Lake through an 84-inch diameter
pipe to Big Creek Powerhouse No. 1.; (ii) Tunnel No. 2, approximately
4.1 miles long, conveys water from the Dam 4 impoundment just
downstream of Powerhouse 1 to Big Creek Powerhouse No. 2. Water from
Ely and Balsam Creek diversions also enter into Tunnel No. 2 between
the forebay and powerhouse; and (iii) The Shoo Fly, conveys water from
Shaver Lake (FERC Project No. 67) through Tunnel 5 and into Tunnel 2
leading to Powerhouse No. 2. The Shoo Fly was used during the
construction of Shaver Lake Dam and Powerhouse No. 2A to keep water off
the dam and to get more generation from Powerhouse No. 2. Although not
currently in use, the Shoo Fly Complex gives SCE the flexibility to
divert water from Shaver Lake to Powerhouse No. 2, if required.
    m. A copy of the application is available for review at the
Commission in the Public Reference Room or may be viewed on the
Commission's Web site at http://www.ferc.gov using the ``eLibrary''

link. Enter the docket number excluding the three digits in the docket
number field to access the document. For assistance, please contact
FERC Online Support at<EMAIL_ADDRESS>or toll free at (866)
208-3676, or for TTY, contact<PHONE_NUMBER>. A copy is also available
for inspection and reproduction at the address in item h above.
    You may also register online at http://www.ferc.gov/docs-filing/esubscription.asp
 to be notified via e-mail of new filings and

issuances related to this or other pending projects. For assistance,
contact FERC Online Support.
    n. Anyone may submit a protest or a motion to intervene in
accordance with the requirements of Rules of Practice and Procedure, 18
CFR 385.210, 385.211, and 385.214. In determining the appropriate
action to take, the Commission will consider all protests filed, but
only those who file a motion to intervene in accordance with the
Commission's Rules may become a party to the proceeding. Any protests
or motions to intervene must be received on or before the specified
deadline date for the particular application.
    All filings must (1) bear in all capital letters the title
``PROTEST'' or ``MOTION TO INTERVENE;'' (2) set forth in the heading
the name of the applicant and the project number of the application to
which the filing responds; (3) furnish the name, address, and telephone
number of the person protesting or intervening; and (4) otherwise
comply with the requirements of 18 CFR 385.2001 through 385.2005.
Agencies may obtain copies of the application directly from the
applicant. A copy of any protest or motion to intervene must be served
upon each representative of the applicant specified in the particular
application.

Kimberly D. Bose,
Secretary.
 [FR Doc. E7-13519 Filed 7-11-07; 8:45 am]

BILLING CODE 6717-01-P


supra Section II.J. Moreover, the Commission adopted a contract-
based definition of ``project'' in 2016 and, although the Commission
left ``project'' undefined in 2012, it provided guidance in that
rulemaking suggesting that project was to be determined based on the
underlying contract. See 2012 Rules Adopting Release, Section
II.D.3. In contrast, among other changes, the proposed rules include
a broader definition of project and would permit greater aggregation
of payment information at the major subnational jurisdiction level.
See supra Sections II.F. and II.G.
---------------------------------------------------------------------------

    For PRA purposes, we estimate that the incremental burden of the
proposed rules would be at least 25 percent less than the incremental
burden of the 2016 Rules. We believe that this reduction in the burden
estimate is reasonable because of the proposed changes to the
definition of project, which should generally simplify and reduce the
collection and reporting of payment information for a resource
extraction issuer.\391\ We note that this reduction in the burden
estimate does not take into account the two new proposed exemptions for
conflicts with foreign law and pre-existing contracts.\392\ While we
expect these proposed exemptions would result in a reduced PRA burden
compared to the 2016 Rules,\393\ because it is more difficult to
estimate the effects of the proposed exemptions, and to avoid
underestimating the proposed rules' burden and costs, we have not
factored them into the current PRA estimates. We have relied on a prior
commenter's estimates for the limited purpose of this PRA analysis,
and, as indicated above, we request commenters to provide us with more
accurate estimates of the compliance costs and burden of the proposed
rules.\394\
---------------------------------------------------------------------------

    \391\ See supra Section II.F.2.
    \392\ See supra Section III.C.
    \393\ For example, issuers may spend fewer internal hours and/or
incur fewer professional costs to prepare case-specific exemptive
relief requests in connection with the required disclosures.
    \394\ See discussion of quantitative estimate of costs in
Section III.C.11., above.
---------------------------------------------------------------------------

    Thus, for an issuer bearing the full costs and burden of the
proposed rules, we estimate that compliance with the proposed rules
would require 375 hours to make initial changes to the issuer's
internal books and records and another 375 hours a year on an ongoing
basis to review and verify the payment information,\395\ resulting in
750 hours per respondent for the initial incremental PRA burden. Using
the three-year average of the expected burden during the first year and
the expected ongoing burden during the next two years, we estimate that
the incremental PRA burden would be 500 hours per fully affected
respondent (750 + 375 + 375 hours/3 years).
---------------------------------------------------------------------------

    \395\ 500 hours x .25 = 125 hours. 500 hours-125 = 375 hours.
---------------------------------------------------------------------------

    The following table shows the estimated internal burden hours and
professional and other external costs for the 236 issuers bearing the
full costs and burden of the proposed rules and for the 109 issuers
subject to more granular resource extraction payment disclosure
requirements in foreign jurisdictions when preparing and submitting
Form SD. These total burden hours and total external costs would be in
addition to the existing estimated hour and cost burdens applicable to
Form SD because of compliance with Exchange Act Rule 13p-1.

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Additional
                                                   Burden       Total       Internal   Professional  Professional   (external)
                                    Number of    hours per      burden       burden     (external)    (external)     IT costs      Total        Total
   Whether issuer is subject to     estimated     current     hours for    hours for     hours for     costs for     \2\ per     additional    external
similar foreign disclosure regime    affected     affected     current      current       current       current      current      IT costs      costs
                                    responses     response     affected     affected     affected      affected      affected
                                                              responses    responses     responses     responses     response
                                           (A)          (B)          (C)          (D)           (E)           (F)          (G)          (H)          (I)
                                                             = (A) x (B)  = (C) x .75   = (C) x .25  = (E) x $400               = (A) x (G)  = (F) + (H)
--------------------------------------------------------------------------------------------------------------------------------------------------------
No...............................          236          500      118,000       88,500        29,500   $11,800,000      $75,000  $17,700,000  $29,772,500
Yes..............................          109           25    \1\ 2,725        2,044        681.25       272,500            0            0      272,500
                                  ----------------------------------------------------------------------------------------------------------------------
    Total........................          345  ...........  ...........       90,544  ............    12,072,500  ...........   17,700,000   30,045,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ As we did in the 2016 rulemaking, we estimate that an issuer that is already subject to a qualifying alternative reporting regime would incur an
  internal burden that is five percent of the burden incurred by a fully affected issuer. 500 hours x .05 = 25 hours. 25 hours x 109 = 2,725 hours.
\2\ We estimate that an issuer bearing the full costs of the proposed rules would incur additional initial compliance costs for IT consulting, training
  and travel of $75,000. We do not, however, believe that these initial IT costs would apply to the issuers that are already subject to a qualifying
  alternative reporting regime since those issuers should already have IT systems in place to comply with the foreign regime. Similar to our estimate of
  the incremental PRA burden of the proposed rules, we estimate that the additional initial compliance costs for IT consulting, training and travel
  would be at least 25 percent less than the estimate for those costs ($100,000 per respondent) that was factored into the PRA estimate of total
  professional costs for the 2016 Rules. $100,000 x .25 = $25,000. $100,000-25,000 = $75,000.

D. Request for Comment

    We request comment in order to:
     Evaluate whether the proposed collection of information is
necessary for the proper performance of the functions of the agency,
including whether the information would have practical utility;
     Evaluate the accuracy of our estimate of the burden of the
proposed collection of information;
     Determine whether there are ways to enhance the quality,
utility, and clarity of the information to be collected;
     Evaluate whether there are ways to minimize the burden of
the collection of information on those who are to respond, including
through the use of automated collection techniques or other forms of
information technology; and
     Evaluate whether the proposed amendments would have any
effects on any other collections of information not previously
identified in this section.\396\
---------------------------------------------------------------------------

    \396\ We request comment pursuant to 44 U.S.C. 3506(c)(2)(B).
---------------------------------------------------------------------------

    Any member of the public may direct to us any comments about the
accuracy of these burden estimates and any suggestions for reducing
these burdens. Persons submitting comments on the collection of
information requirements should direct the comments to the Office of
Management and Budget, Attention: Desk Officer for the Securities and
Exchange Commission, Office of Information and Regulatory Affairs,
Washington, DC 20503, and should send a copy to Vanessa A. Countryman,
Secretary, Securities and Exchange Commission, 100 F Street NE,
Washington, DC 20549-1090, with reference to File No. S7-24-19.
Requests for materials submitted to OMB by the Commission with regard
to these collections of information should be in writing, refer to File
No. S7-24-19, and be submitted to the Securities and Exchange
Commission, Office of FOIA Services, 100 F Street NE, Washington, DC
20549-2736. OMB is required to make a decision concerning the
collection of information between 30 and 60 days after publication of
this release. Consequently, a comment to OMB is best assured of having
its full effect if OMB receives it within 30 days of publication.

V. Small Business Regulatory Enforcement Fairness Act

    For purposes of the Small Business Regulatory Enforcement Fairness
Act of 1996,\397\ a rule is ``major'' if it has resulted, or is likely
to result in:
---------------------------------------------------------------------------

    \397\ 5 U.S.C. 801 et seq.
---------------------------------------------------------------------------

     An annual effect on the U.S. economy of $100 million or
more;
     A major increase in costs or prices for consumers or
individual industries; or
     Significant adverse effects on competition, investment, or
innovation.
    We request comment on whether our proposal would be a ``major
rule'' for purposes of the Small Business Regulatory Enforcement
Fairness Act. We solicit comment and empirical data on:
     The potential effect on the U.S. economy on an annual
basis;
     Any potential increase in costs or prices for consumers or
individual industries; and
     Any potential effect on competition, investment, or
innovation.

VI. Regulatory Flexibility Act Certification

    When an agency issues a rulemaking proposal, the Regulatory
Flexibility Act (``RFA'') \398\ requires the agency to prepare and make
available for public comment an Initial Regulatory Flexibility Analysis
(``IRFA'') that will describe the impact of the proposed rule on small
entities.\399\ Section 605 of the RFA allows an agency to certify a
rule, in lieu of preparing an IRFA, if the proposed rulemaking is not
expected to have a significant economic impact on a substantial number
of small entities.\400\
---------------------------------------------------------------------------

    \398\ 5 U.S.C. 601 et seq.
    \399\ 5 U.S.C. 603(a).
    \400\ 5 U.S.C. 605(b).
---------------------------------------------------------------------------

    The proposed rules would exempt smaller reporting companies and
emerging growth companies from the requirements of Section 13(q) and
proposed Rule 13q-1. Most small entities \401\ would fall within the
scope of this exemption and, therefore, would not be subject to the
proposed rules. Accordingly, the Commission hereby certifies, pursuant
to 5 U.S.C. 605(b), that the proposed rules, including proposed Rule
13q-1 and the amendments to Form SD, if adopted, would not have a
significant economic impact on a substantial number of small entities
for purposes of the RFA.
---------------------------------------------------------------------------

    \401\ For purposes of the RFA, Exchange Act Rule 0-10(a) [17 CFR
240.0-10(a)] defines an issuer (other than an investment company) to
be a ``small business'' or ``small organization'' if it had total
assets of $5 million or less on the last day of its most recent
fiscal year. Because Exchange Act Rule 12b-2 defines a smaller
reporting company as an issuer (that is not an investment company)
with either a public float of less than $250 million, or annual
revenues of less than $100 million for the previous year and either
no public float or a public float of less than $700 million, most
small entities would likely fall within the definition of smaller
reporting company and, therefore, would be exempt from the proposed
rules.
---------------------------------------------------------------------------

Request for Comment
    We request comment on this certification. In particular, we solicit
comment on the following: Do commenters agree with the certification?
If not, please describe the nature of any impact of the proposed
amendments on small entities and provide empirical data to illustrate
the extent of the impact. Such comments will be considered in the
preparation of the

final rules (and in a Final Regulatory Flexibility Analysis if one is
needed) and, if the proposed rules are adopted, will be placed in the
same public file as comments on the proposed rules themselves.

VII. Statutory Authority and Text of Proposed Rule and Form Amendments

    We are proposing the rule and form amendments contained in this
document under the authority set forth in Sections 3(b), 12, 13, 15,
23(a), and 36 of the Exchange Act.

List of Subjects in 17 CFR Parts 240 and 249b

    Reporting and recordkeeping requirements, Securities.

    In accordance with the foregoing, we propose to amend title 17,
chapter II of the Code of Federal Regulations as follows:

PART 240--GENERAL RULES AND REGULATIONS, SECURITIES EXCHANGE ACT OF
1934

0
1. The general authority citation for part 240 continues to read as
follows:

    Authority: 15 U.S.C. 77c, 77d, 77g, 77j, 77s, 77z-2, 77z-3,
77eee, 77ggg, 77nnn, 77sss, 77ttt, 78c, 78c-3, 78c-5, 78d, 78e, 78f,
78g, 78i, 78j, 78j-1, 78k, 78k-1, 78l, 78m, 78n, 78n-1, 78o, 78o-4,
78o-10, 78p, 78q, 78q-1, 78s, 78u-5, 78w, 78x, 78ll, 78mm, 80a-20,
80a-23, 80a-29, 80a-37, 80b-3, 80b-4, 80b-11, and 7201 et seq., and
8302; 7 U.S.C. 2(c)(2)(E); 12 U.S.C. 5221(e)(3); 18 U.S.C. 1350; and
Pub. L. 111-203, 939A, 124 Stat. 1376 (2010); and Pub. L. 112-106,
secs. 503 and 602, 126 Stat. 326 (2012), unless otherwise noted.

* * * * *
0
2. Section 240.13q-1 is revised to read as follows:

Sec.  240.13q-1  Disclosure of payments made by resource extraction
issuers.

    (a) Resource extraction issuers. Every issuer that is required to
file an annual report with the Commission on Form 10-K (17 CFR
249.310), Form 20-F (17 CFR 249.220f), or Form 40-F (17 CFR 249.240f)
pursuant to Section 13 or 15(d) of the Exchange Act (15 U.S.C. 78m or
78o(d)) and engages in the commercial development of oil, natural gas,
or minerals must furnish a report on Form SD (17 CFR 249b.400) within
the period specified in that Form disclosing the information required
by the applicable items of Form SD as specified in that Form.
    (b) Anti-evasion. Disclosure is required under this section in
circumstances in which an activity related to the commercial
development of oil, natural gas, or minerals, or a payment or series of
payments made by a resource extraction issuer to a foreign government
or the Federal Government for the purpose of commercial development of
oil, natural gas, or minerals, is not, in form or characterization,
within one of the categories of activities or payments specified in
Form SD, but is part of a plan or scheme to evade the disclosure
required under this section.
    (c) Alternative reporting. An application for recognition by the
Commission that an alternative reporting regime requires disclosure
that satisfies the transparency objectives of Section 13(q) (15 U.S.C.
78m(q)), for purposes of alternative reporting pursuant to Item 2.01(c)
of Form SD, must be filed in accordance with the procedures set forth
in Sec.  240.0-13, except that, for purposes of this paragraph (c),
applications may be submitted by resource extraction issuers,
governments, industry groups, or trade associations.
    (d) Exemptions--(1) Conflicts of law. A resource extraction issuer
that is prohibited by the law of the jurisdiction where the project is
located from providing the payment information required by Form SD may
exclude such disclosure, subject to the following conditions:
    (i) The issuer has taken all reasonable steps to seek and use any
exemptions or other relief under the applicable law of the foreign
jurisdiction, and has been unable to obtain or use such an exemption or
other relief;
    (ii) The issuer must disclose on Form SD:
    (A) The foreign jurisdiction for which it is omitting the
disclosure pursuant to this paragraph (d)(1);
    (B) The particular law of that jurisdiction that prevents the
issuer from providing such disclosure; and
    (C) The efforts the issuer has undertaken to seek and use
exemptions or other relief under the applicable law of that
jurisdiction, and the results of those efforts; and
    (iii) The issuer must furnish as an exhibit to Form SD a legal
opinion from counsel that opines on the issuer's inability to provide
such disclosure without violating the foreign jurisdiction's law.
    (2) Conflicts with pre-existing contracts. A resource extraction
issuer that is unable to provide the payment information required by
Form SD without violating one or more contract terms that were in
effect prior to the effective date of this section may exclude such
disclosure, subject to the following conditions:
    (i) The issuer has taken all reasonable steps to obtain the consent
of the relevant contractual parties, or to seek and use another
contractual exception or relief, to disclose the payment information,
and has been unable to obtain such consent or other contractual
exception or relief;
    (ii) The issuer must disclose on Form SD:
    (A) The jurisdiction for which it is omitting the disclosure
pursuant to this paragraph (d)(2);
    (B) The particular contract terms that prohibit the issuer from
providing such disclosure; and
    (C) The efforts the issuer has undertaken to obtain the consent of
the contracting parties, or to seek and use another contractual
exception or relief, to disclose the payment information, and the
results of those efforts; and
    (iii) The issuer must furnish as an exhibit to Form SD a legal
opinion from counsel that opines on the issuer's inability to provide
such disclosure without violating the contractual terms.
    (3) Exemption for emerging growth companies and smaller reporting
companies. An issuer that is an emerging growth company or a smaller
reporting company, each as defined under Sec.  240.12b-2, is exempt
from, and need not comply with, the requirements of this section.
    (4) Case-by-case exemption. A resource extraction issuer may file
an application for exemptive relief under this section in accordance
with the procedures set forth in Sec.  240.0-12.
    (e) Compilation. To the extent practicable, the staff will
periodically make a compilation of the information required to be
submitted under this section publicly available online. The staff may
determine the form, manner and timing of the compilation, except that
no information included therein may be anonymized (whether by redacting
the names of the resource extraction issuers or otherwise).

PART 249b--FURTHER FORMS, SECURITIES EXCHANGE ACT OF 1934

0
3. The authority citation for part 249b continues to read, in part, as
follows:

    Authority: 15 U.S.C. 78a et seq., unless otherwise noted.
* * * * *

    Section 249b.400 is also issued under secs. 1502 and 1504, Pub.
L. 111-203, 124 Stat. 2213 and 2220.

0
4. Amend Form SD (referenced in Sec.  249b.400) by:
0
a. Adding a check box for Rule 13q-1;
0
b. Revising instruction A. under ``General Instructions'';
0
c. Redesignating instruction B.2. as B.3 and adding new instructions
B.2.

and B.4. under the ``General Instructions''; and
0
d. Redesignating Section 2 as Section 3, adding new Section 2, and
revising newly redesignated Section 3 under the ``Information to be
Included in the Report''.
    The addition and revision read as follows:

    Note: The text of Form SD does not, and this amendment will not,
appear in the Code of Federal Regulations.

                                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                                              Washington, DC 20549
                                                     FORM SD
                                          Specialized Disclosure Report

----------------------------------------------------------------------------------------------------------------
                           (Exact name of the registrant as specified in its charter)

----------------------------------------------------------------------------------------------------------------
(State or other jurisdiction of       (Commission                           (I.R.S. Employer
incorporation or organization)        File Number)                          Identification No.)

----------------------------------------------------------------------------------------------------------------
                              (Full mailing address of principal executive offices)

----------------------------------------------------------------------------------------------------------------
   (Name and telephone number, including area code, of the person to contact in connection with this report.)

Check the appropriate box to indicate the rule pursuant to which this Form is being submitted, and provide the
 period to which the information in this Form applies:

__Rule 13p-1 under the Securities Exchange Act (17 CFR 240.13p-1) for the reporting period from January 1 to
 December 31, ____.
__Rule 13q-1 under the Securities Exchange Act (17 CFR 240.13q-1) for the fiscal year ended ____.

GENERAL INSTRUCTIONS

A. Rule as to Use of Form SD

    This Form shall be used for a report pursuant to Rule 13p-1 (17 CFR
240.13p-1) and Rule 13q-1 (17 CFR 240.13q-1) under the Securities
Exchange Act of 1934 (the ``Exchange Act'').

B. Information To Be Reported and Time for Furnishing Reports

    1. * * *
    2. Form furnished under Rule 13q-1. If your fiscal year ends on or
before June 30, furnish the information required by Section 2 of this
form on EDGAR no later than March 31 in the calendar year following
your most recent fiscal year. If your fiscal year ends after June 30,
furnish this required information no later than March 31 in the second
calendar year following your most recent fiscal year.
    3. If the deadline for furnishing this Form occurs on a Saturday,
Sunday or holiday on which the Commission is not open for business,
then the deadline shall be the next business day.
    4. The information and documents furnished in this report shall not
be deemed to be incorporated by reference into any filing under the
Securities Act or the Exchange Act, unless a registrant specifically
incorporates it by reference into such filing.
* * * * *

INFORMATION TO BE INCLUDED IN THE REPORT

* * * * *

Section 2--Resource Extraction Issuer Disclosure

Item 2.01 Resource Extraction Issuer Disclosure and Report

    (a) Required Disclosure. (1) A resource extraction issuer must
furnish an annual report on Form SD with the Commission, and include as
an exhibit to this Form SD, the information specified in Item
2.01(a)(5) of this Form, relating to any payment made during the fiscal
year covered by the annual report by the resource extraction issuer, a
subsidiary of the resource extraction issuer, or an entity under the
control of the resource extraction issuer, to a foreign government or
the Federal Government, for the purpose of the commercial development
of oil, natural gas, or minerals.
    (2) The resource extraction issuer is not required to have the
information audited. The payment information must be provided on a cash
basis and not an accrual basis.
    (3) The resource extraction issuer must provide a statement in the
body of the Form SD, under the caption ``Disclosure of Payments by
Resource Extraction Issuers,'' that the specified payment disclosure
required by this Form is included in an exhibit to the Form SD.
    (4) A resource extraction issuer that is claiming an exemption
under Rule 13q-1(d)(1) or (2) (17 CFR 240.13q-1(d)(1) or (2)) must
provide the disclosure required by those rules, as applicable, in the
body of the Form SD. If applicable, a resource extraction issuer must
disclose in the body of Form SD that it has filed an application for
exemptive relief pursuant to Rule 13q-1(d)(4) (17 CFR 240.13q-1(d)(4)).
    (5) The resource extraction issuer must include the following
information in the exhibit to Form SD, which must present the
information in the eXtensible Business Reporting Language (XBRL)
electronic format:
    (i) The type and total amount of such payments, by payment type
listed in paragraph (d)(9)(iii) of this Item, made for each project of
the resource extraction issuer relating to the commercial development
of oil, natural gas, or minerals;
    (ii) The type and total amount of such payments, by payment type
listed in paragraph (d)(9)(iii) of this Item, for all projects made to
each government;
    (iii) The total amounts of the payments, by payment type listed in
paragraph (d)(9)(iii) of this Item;
    (iv) The currency used to make the payments;
    (v) The fiscal year in which the payments were made;
    (vi) The business segment of the resource extraction issuer that
made the payments;

    (vii) The governments (including any foreign government or the
Federal Government) that received the payments and the country in which
each such government is located;
    (viii) The project of the resource extraction issuer to which the
payments relate;
    (ix) The particular resource that is the subject of commercial
development;
    (x) The method of extraction used in the project; and
    (xi) The major subnational political jurisdiction of the project.
    (b) Delayed Reporting. (1) A resource extraction issuer may delay
disclosing payment information related to exploratory activities until
the Form SD submitted for the fiscal year immediately following the
fiscal year in which the payment was made. For purposes of this
paragraph, payment information related to exploratory activities
includes all payments made as part of the process of (i) identifying
areas that may warrant examination, (ii) examining specific areas that
are considered to have prospects of containing oil and gas reserves, or
(iii) as part of a mineral exploration program, in each case limited to
exploratory activities that were commenced prior to the commercial
development (other than exploration) of the oil, natural gas, or
minerals on the property, any adjacent property, or any property that
is part of the same project.
    (2) A resource extraction issuer that has acquired (or otherwise
obtains control over) an entity that has not been obligated to provide
disclosure pursuant to Rule 13q-1, or pursuant to another alternative
reporting regime deemed by the Commission to require disclosure that
satisfies the transparency objectives of Section 13(q) (15 U.S.C.
78m(q)), in such entity's last full fiscal year is not required to
commence reporting payment information for such acquired entity until
the Form SD submitted for the fiscal year immediately following the
effective date of the acquisition. A resource extraction issuer must
disclose that it is relying on this accommodation in the body of its
Form SD submission.
    (3) A resource extraction issuer that has completed its initial
public offering in the United States in its last full fiscal year is
not required to commence reporting payment information pursuant to Rule
13q-1 until the Form SD submitted for the fiscal year immediately
following the fiscal year in which the registration statement for its
U.S. initial public offering became effective.
    (c) Alternative Reporting. (1) A resource extraction issuer that is
subject to the resource extraction payment disclosure requirements of
an alternative reporting regime, which has been deemed by the
Commission to require disclosure that satisfies the transparency
objectives of Section 13(q) (15 U.S.C. 78m(q)), may satisfy its
disclosure obligations under paragraph (a) of this Item 2.01 by
including, as an exhibit to this Form SD, a report complying with the
reporting requirements of the alternative jurisdiction.
    (2) The alternative report must be the same as the one prepared and
made publicly available pursuant to the requirements of the approved
alternative reporting regime, subject to changes necessary to comply
with any conditions to alternative reporting set forth by the
Commission.
    (3) The resource extraction issuer must: (i) State in the body of
the Form SD that it is relying on the alternative reporting provision;
(ii) identify the alternative reporting regime for which the report was
prepared; (iii) describe how to access the publicly submitted report in
the alternative jurisdiction; and (iv) specify that the payment
disclosure required by this Form is included in an exhibit to this Form
SD.
    (4) The alternative report must be provided in XBRL format.
    (5) A fair and accurate English translation of the entire report
must be submitted if the report is in a foreign language. Project names
may be presented in their original language, in addition to the English
translation of the project name, if the resource extraction issuer
believes that such an approach would facilitate identification of the
project by users of the disclosure.
    (6) A resource extraction issuer may follow the submission deadline
of an approved alternative jurisdiction if it submits a notice on Form
SD-N on or before the due date of its Form SD indicating its intent to
submit the alternative report using the alternative jurisdiction's
deadline. If a resource extraction issuer fails to submit such notice
on a timely basis, or submits such a notice but fails to submit the
alternative report within four business days of the alternative
jurisdiction's deadline, it may not rely on this Item 2.01(c) for the
following fiscal year.
    (7) Resource extraction issuers must also comply with any
additional requirements that are provided by the Commission upon
granting an alternative reporting accommodation, as well as subsequent
changes in such requirements.
    (d) Definitions. For purposes of this item, the following
definitions apply:
    (1) Business segment means a business segment consistent with the
reportable segments used by the resource extraction issuer for purposes
of financial reporting.
    (2) Commercial development of oil, natural gas, or minerals means
exploration, extraction, processing, and export of oil, natural gas, or
minerals, or the acquisition of a license for any such activity.
    (3) Control means that the resource extraction issuer consolidates
the entity under the accounting principles applicable to the financial
statements included in the resource extraction issuer's periodic
reports filed pursuant to the Exchange Act (i.e., under generally
accepted accounting principles in the United States (U.S. GAAP) or
International Financial Reporting Standards as issued by the
International Accounting Standards Board (IFRS)). A foreign private
issuer that prepares financial statements according to a comprehensive
set of accounting principles, other than U.S. GAAP, and files with the
Commission a reconciliation to U.S. GAAP must determine control using
U.S. GAAP.
    (4) Export means the movement of a resource across an international
border from the host country to another country by a company with an
ownership interest in the resource. Export does not include the
movement of a resource across an international border by a company that
(i) is not engaged in the exploration, extraction, or processing of
oil, natural gas, or minerals and (ii) acquired its ownership interest
in the resource directly or indirectly from a foreign government or the
Federal Government. Export also does not include cross-border
transportation activities by an entity that is functioning solely as a
service provider, with no ownership interest in the resource being
transported.
    (5) Extraction means the production of oil and natural gas as well
as the extraction of minerals.
    (6) Federal Government means the Federal Government of the United
States.
    (7) Foreign Government means a foreign government, a department,
agency, or instrumentality of a foreign government, or a company at
least majority owned by a foreign government. As used in this Item
2.01, foreign government includes a foreign national government as well
as a foreign subnational government, such as the government of a state,
province, county, district, municipality, or territory under a foreign
national government.
    (8) Not de minimis means any Payment made to each Foreign
Government in a host country or the Federal Government that equals or

exceeds $150,000, or its equivalent in the issuer's reporting currency,
whether made as a single payment or series of related payments, subject
to the condition that single payment (or a series of related payments)
disclosure for a Project is only required if the total Payments for a
Project equal or exceed $750,000. In the case of any arrangement
providing for periodic payments or installments, a resource extraction
issuer must use the aggregate amount of the related periodic payments
or installments of the related payments in determining whether the
payment threshold has been met for that series of payments, and
accordingly, whether disclosure is required.
    (9) Payment means an amount paid that:
    (i) Is made to further the commercial development of oil, natural
gas, or minerals;
    (ii) Is not de minimis; and
    (iii) Is one or more of the following:
    (A) Taxes;
    (B) Royalties;
    (C) Fees;
    (D) Production entitlements;
    (E) Bonuses;
    (F) Dividends;
    (G) Payments for infrastructure improvements; and
    (H) Community and social responsibility payments that are required
by law or contract.
    (10) Project is defined by using the following three criteria:
    (i) The type of resource being commercially developed;
    (ii) The method of extraction; and
    (iii) The major subnational political jurisdiction where the
commercial development of the resource is taking place.
    (11) Resource extraction issuer means an issuer that:
    (i) Is required to file an annual report with the Commission on
Form 10-K (17 CFR 249.310), Form 20-F (18 CFR 249.220f), or Form 40-F
(17 CFR 249.240f) pursuant to Section 13 or 15(d) of the Exchange Act
(15 U.S.C. 78m or 78o(d)); and
    (ii) Engages in the commercial development of oil, natural gas, or
minerals.
    (12) Subsidiary means an entity controlled directly or indirectly
through one or more intermediaries.

Instructions to Item 2.01

Disclosure by Subsidiaries and Other Controlled Entities

    (1) If a resource extraction issuer is controlled by another
resource extraction issuer that has submitted a Form SD disclosing the
information required by Item 2.01 for the controlled entity, then such
controlled entity is not required to provide the disclosure required by
Item 2.01 separately. In such circumstances, the controlled entity must
submit a notice on Form SD indicating that the required disclosure was
submitted on Form SD by the controlling entity, identifying the
controlling entity and the date it submitted the disclosure. The
reporting controlling entity must note that it is submitting the
required disclosure for a controlled entity and must identify the
controlled entity on its Form SD submission.

Currency Disclosure and Conversion

    (2) A resource extraction issuer must report the amount of payments
made for each payment type, and the total amount of payments made for
each project and to each government, during the reporting period in
either U.S. dollars or the resource extraction issuer's reporting
currency. If a resource extraction issuer has made payments in
currencies other than U.S. dollars or its reporting currency, it may
choose to calculate the currency conversion between the currency in
which the payment was made and U.S. dollars or the resource extraction
issuer's reporting currency, as applicable, in one of three ways: (a)
By translating the expenses at the exchange rate existing at the time
the payment is made; (b) using a weighted average of the exchange rates
during the period; or (c) based on the exchange rate as of the resource
extraction issuer's fiscal year end. When calculating whether the de
minimis threshold has been exceeded, a resource extraction issuer may
be required to convert the payment to U.S. dollars, even though it is
not required to disclose those payments in U.S. dollars. For example,
this may occur when the resource extraction issuer is using a non-U.S.
dollar reporting currency. In these instances, the resource extraction
issuer may use any of the three methods described above for calculating
the currency conversion. In all cases a resource extraction issuer must
disclose the method used to calculate the currency conversion and must
choose a consistent method for all such currency conversions within a
particular Form SD submission.

Location Tagging

    (3) When identifying the country and major subnational political
jurisdiction where the commercial development of the resource is taking
place, a resource extraction issuer must use the combined country and
subdivision code provided in ISO 3166, if available. When identifying
the country in which a government is located, a resource extraction
issuer must use the two letter country code provided in ISO 3166, if
available.

Entity Level Disclosure and Tagging

    (4) If a government levies a payment obligation, such as a tax or a
requirement to pay a dividend, at the entity level rather than on a
particular project, a resource extraction issuer may disclose that
payment at the entity level. To the extent that payments, such as
corporate income taxes and dividends, are made for obligations levied
at the entity level, a resource extraction issuer may omit certain tags
that may be inapplicable (e.g., project tag, business segment tag) for
those payment types as long as it provides all other electronic tags,
including the tag identifying the recipient government.

Project Disclosure

    (5)(i) When identifying the type of resource that is being
commercially developed for purposes of identifying a project, the
resource extraction issuer must identify whether the resource is oil,
natural gas, or a type of mineral. A resource extraction issuer should
identify synthetic oil obtained through processing tar sands, bitumen,
or oil shales as ``oil'' and should identify gas obtained from methane
hydrates as ``natural gas.'' Synthetic oil or gas obtained through
processing of coal should be identified as ``coal.'' Minerals must be
identified by type, such as gold, copper, coal, sand, or gravel, but
additional detail is not required. For information on which materials
are covered by the term ``minerals,'' refer to Instruction 13 below.
    (ii) When identifying the method of extraction for purposes of
identifying a project, the resource extraction issuer must choose from
the following three parameters: well, open pit, or underground mining.
    (iii) When identifying the national and major subnational political
jurisdiction for purposes of identifying a project, refer to
Instruction 3 to Item 2.01. Onshore and offshore development of
resources may not be treated as a single project. A resource extraction
issuer must identify when a project is offshore and identify the
nearest major subnational political jurisdiction pursuant to
Instruction 3 of Item 2.01.
    (iv) A resource extraction issuer may treat all the activities
within a major subnational political jurisdiction as a single project,
but must describe each type of resource being commercially developed
and each method of extraction used in the description of the

project. A resource extraction issuer may not combine as one project
activities that cross the borders of a major subnational political
jurisdiction.

Payment Disclosure

    (6) When a resource extraction issuer proportionately consolidates
an entity or operation under U.S. GAAP or IFRS, as applicable, the
resource extraction issuer must disclose its proportionate amount of
the payments made by such entity or operation pursuant to this Item and
must indicate the proportionate interest.
    (7) Although an entity providing only services to a resource
extraction issuer to assist with exploration, extraction, processing or
export would generally not be considered a resource extraction issuer,
where such a service provider makes a payment that falls within the
definition of ``payment'' to a government on behalf of a resource
extraction issuer, the resource extraction issuer must disclose such
payment.
    (8) ``Processing,'' as used in Item 2.01, includes, but is not
limited to, midstream activities such as removing liquid hydrocarbons
from gas, removing impurities from natural gas prior to its transport
through a pipeline, and upgrading bitumen or heavy oil, through the
earlier of the point at which oil, gas, or gas liquids (natural or
synthetic) are either sold to an unrelated third party or delivered to
a main pipeline, a common carrier, or a marine terminal. It also
includes the crushing or preparing of raw ore prior to the smelting
phase. It would not include the downstream activities of refining or
smelting.
    (9) A resource extraction issuer must disclose payments made for
taxes on corporate profits, corporate income, and production.
Disclosure of payments made for taxes levied on consumption, such as
value added taxes, personal income taxes, or sales taxes, is not
required.
    (10) Royalties include unit-based, value-based, and profit-based
royalties. Fees include license fees, rental fees, entry fees, and
other considerations for licenses or concessions. Bonuses include
signature, discovery, and production bonuses.
    (11) Dividends paid to a government as a common or ordinary
shareholder of the resource extraction issuer that are paid to the
government under the same terms as other shareholders need not be
disclosed. The resource extraction issuer, however, must disclose any
dividends paid in lieu of production entitlements or royalties.
    (12) If a resource extraction issuer makes an in-kind payment of
the types of payments required to be disclosed, the resource extraction
issuer must disclose the payment. When reporting an in-kind payment, a
resource extraction issuer must determine the monetary value of the in-
kind payment and tag the information as ``in-kind'' for purposes of the
currency. For purposes of the disclosure, a resource extraction issuer
must report the payment at cost, or if cost is not determinable, fair
market value and must provide a brief description of how the monetary
value was calculated. If a resource extraction issuer makes an in-kind
production entitlement payment under the rules and then repurchases the
resources associated with the production entitlement within the same
fiscal year, the resource extraction issuer must report the payment
using the purchase price (rather than at cost, or if cost is not
determinable, fair market value). If the in-kind production entitlement
payment and the subsequent repurchase are made in different fiscal
years and the purchase price is greater than the previously reported
value of the in-kind payment, the resource extraction issuer must
report the difference in values in the latter fiscal year (assuming the
amount of that difference exceeds the de minimis threshold). In other
situations, such as when the purchase price in a subsequent fiscal year
is less than the in-kind value already reported, no disclosure relating
to the purchase price is required.
    (13) ``Minerals,'' as used in Item 2.01, includes any material for
which an issuer with mining operations would provide disclosure under
the Commission's existing disclosure requirements and policies,
including Industry Guide 7 or any successor requirements or policies
(see subpart 1300 of Regulation S-K (17 CFR 229.1300). It does not
include oil and gas resources (as defined in 17 CFR 210.4-10(a)(16)(D)
or any successor provision).
    (14) For payments made at a level below the major subnational
government level, such as a county, district, or municipality, an
issuer may aggregate all of its payments of a particular payment type
made to such subnational governments and disclose the aggregate amount
without having to identify the particular subnational government payee.
The issuer should instead generically identify the subnational
government payee (e.g., as ``county,'' ``municipality,'' or some
combination of subnational governments).

Section 3--Exhibits

Item 3.01 Exhibits

    List below the following exhibits submitted as part of this report:
    Exhibit 1.01--Conflict Minerals Report as required by Items 1.01
and 1.02 of this Form.
    Exhibit 2.01--Resource Extraction Payment Report as required by
Item 2.01 of this Form.
    Exhibit 3.01--Opinion of Counsel as required by Rule 13q-1(d)(1) or
(2) (17 CFR 240.13q-1(d)(1) or (2)).

SIGNATURES

    Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its
behalf by the duly authorized undersigned.

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(Registrant)

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By (Signature and Title) *

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(Date)

* Print name and title of the registrant's signing executive officer
under his or her signature.
* * * * *

    By the Commission.

    Dated: December 18, 2019.
Vanessa A. Countryman,
Secretary.
[FR Doc. 2019-28407 Filed 1-14-20; 8:45 am]
 BILLING CODE 8011-01-P