Establishing Interregional Transfer Capability Transmission Planning and Cost Allocation Requirements; Supplemental Notice of Staff-Led Workshop, 74612-74616 [2022-26474]
Download as PDF
<![CDATA[
lotter on DSK11XQN23PROD with NOTICES1
74612
Federal Register / Vol. 87, No. 233 / Tuesday, December 6, 2022 / Notices
the requirements of Rules of Practice
and Procedure, 18 CFR 385.210 and
385.214. Any motions to intervene must
be received on or before the specified
deadline date for the particular
proceeding.
Filing and Service of Responsive
Documents: All filings must (1) bear in
all capital letters the ‘‘COMMENTS
CONTESTING QUALIFICATION FOR A
CONDUIT HYDROPOWER FACILITY’’
or ‘‘MOTION TO INTERVENE,’’ as
applicable; (2) state in the heading the
name of the applicant and the project
number of the application to which the
filing responds; (3) state the name,
address, and telephone number of the
person filing; and (4) otherwise comply
with the requirements of sections
385.2001 through 385.2005 of the
Commission’s regulations.1 All
comments contesting Commission staff’s
preliminary determination that the
facility meets the qualifying criteria
must set forth their evidentiary basis.
The Commission strongly encourages
electronic filing. Please file motions to
intervene and comments using the
Commission’s eFiling system at https://
www.ferc.gov/docs-filing/efiling.asp.
Commenters can submit brief comments
up to 6,000 characters, without prior
registration, using the eComment system
at https://www.ferc.gov/docs-filing/
ecomment.asp. You must include your
name and contact information at the end
of your comments. For assistance,
please contact FERC Online Support at
FERCOnlineSupport@ferc.gov, (866)
208–3676 (toll free), or (202) 502–8659
(TTY). In lieu of electronic filing, you
may send a paper copy. 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, MD 20852. A copy of all
other filings in reference to this
application must be accompanied by
proof of service on all persons listed in
the service list prepared by the
Commission in this proceeding, in
accordance with 18 CFR 385.2010.
Locations of Notice of Intent: 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
website at https://www.ferc.gov/docsfiling/elibrary.asp. Enter the docket
number (i.e., CD23–3) in the docket
number field to access the document.
1 18
CFR 385.2001–2005 (2021).
VerDate Sep<11>2014
17:51 Dec 05, 2022
Jkt 259001
You may also register online at https://
www.ferc.gov/docs-filing/
esubscription.asp to be notified via
email of new filings and issuances
related to this or other pending projects.
Copies of the notice of intent can be
obtained directly from the applicant.
For assistance, call toll-free 1–866–208–
3676 or email FERCOnlineSupport@
ferc.gov. For TTY, call (202) 502–8659.
Dated: November 30, 2022.
Kimberly D. Bose,
Secretary.
[FR Doc. 2022–26473 Filed 12–5–22; 8:45 am]
BILLING CODE 6717–01–P
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
[Docket No. ER23–493–000]
Thunder Wolf Energy Center, LLC;
Supplemental Notice That Initial
Market-Based Rate Filing Includes
Request for Blanket Section 204
Authorization
This is a supplemental notice in the
above-referenced proceeding of Thunder
Wolf Energy Center, LLC’s application
for market-based rate authority, with an
accompanying rate tariff, noting that
such application includes a request for
blanket authorization, under 18 CFR
part 34, of future issuances of securities
and assumptions of liability.
Any person desiring to intervene or to
protest should file with the Federal
Energy Regulatory Commission, 888
First Street NE, Washington, DC 20426,
in accordance with Rules 211 and 214
of the Commission’s Rules of Practice
and Procedure (18 CFR 385.211 and
385.214). Anyone filing a motion to
intervene or protest must serve a copy
of that document on the Applicant.
Notice is hereby given that the
deadline for filing protests with regard
to the applicant’s request for blanket
authorization, under 18 CFR part 34, of
future issuances of securities and
assumptions of liability, is December 20,
2022.
The Commission encourages
electronic submission of protests and
interventions in lieu of paper, using the
FERC Online links at https://
www.ferc.gov. To facilitate electronic
service, persons with internet access
who will eFile a document and/or be
listed as a contact for an intervenor
must create and validate an
eRegistration account using the
eRegistration link. Select the eFiling
link to log on and submit the
intervention or protests.
PO 00000
Frm 00018
Fmt 4703
Sfmt 4703
Persons unable to file electronically
may mail similar pleadings to the
Federal Energy Regulatory Commission,
888 First Street NE, Washington, DC
20426. Hand delivered submissions in
docketed proceedings should be
delivered to Health and Human
Services, 12225 Wilkins Avenue,
Rockville, Maryland 20852.
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 (https://
www.ferc.gov) using the ‘‘eLibrary’’ link.
Enter the docket number excluding the
last three digits in the docket number
field to access the document. 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
FERCOnlineSupport@ferc.gov or call
toll-free, (886) 208–3676 or TYY, (202)
502–8659.
Dated: November 30, 2022.
Kimberly D. Bose,
Secretary.
[FR Doc. 2022–26475 Filed 12–5–22; 8:45 am]
BILLING CODE 6717–01–P
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
[Docket No. AD23–3–000]
Establishing Interregional Transfer
Capability Transmission Planning and
Cost Allocation Requirements;
Supplemental Notice of Staff-Led
Workshop
As announced in the Notice of StaffLed Workshop issued in this proceeding
on October 6, 2022, Federal Energy
Regulatory Commission (Commission)
staff will convene a workshop to discuss
whether and how the Commission could
establish a minimum requirement for
Interregional Transfer Capability for
public utility transmission providers in
transmission planning and cost
allocation processes on December 5 and
6, 2022, from approximately 12:00 p.m.
to 5:00 p.m. Eastern Time.
The purpose of this workshop is to
consider the question of whether and
how to establish a minimum
requirement for Interregional Transfer
E:\FR\FM\06DEN1.SGM
06DEN1
74613
Federal Register / Vol. 87, No. 233 / Tuesday, December 6, 2022 / Notices
Capability. Topics for discussion may
include: how to determine the need for
and benefit of setting a minimum
requirement for Interregional Transfer
Capability; what to consider in
establishing a potential Interregional
Transfer Capability requirement,
including who would be responsible for
determining a minimum Interregional
Transfer Capability requirement and
what would be the objective and drivers
of such a requirement; what process
could be used in establishing a
minimum Interregional Transfer
Capability requirement to determine key
data inputs, modeling techniques, and
relevant metrics; and how costs for
transmission facilities intended to
increase Interregional Transfer
Capability should be allocated and how
to ensure a minimum amount of
Interregional Transfer Capability is
achieved and maintained.
While the workshop is not for the
purpose of discussing any specific
matters before the Commission, some
workshop discussions may involve
issues raised in proceedings that are
currently pending before the
Commission. These proceedings
include, but are not limited to:
Docket Nos.
lotter on DSK11XQN23PROD with NOTICES1
Invenergy Transmission LLC .............................................................................................................................
Invenergy Transmission LLC v. Midcontinent Independent System Operator, Inc ...........................................
SOO Green HVDC Link ProjectCo, LLC v. PJM Interconnection, LLC ............................................................
PPL Electric Utilities Corporation, PJM Interconnection, L.L.C .........................................................................
Appalachian Power Company, PJM Interconnection, L.L.C ..............................................................................
Neptune Regional Transmission System, LLC and Long Island Power Authority v. PJM Interconnection,
L.L.C.
WestConnect Public Utilities ..............................................................................................................................
PPL Electric Utilities Corporation .......................................................................................................................
Southwest Power Pool, Inc ................................................................................................................................
Attached to this Supplemental Notice
is an agenda for the workshop, which
includes the workshop program and
expected panelists.
Panelists are asked to submit advance
materials to provide any information
related to their respective panel (e.g.,
summary statements, reports,
whitepapers, studies, or testimonies)
that panelists believe should be
included in the record of this
proceeding by November 21, 2022.
Panelists should file all advance
materials in the AD23–3–000 docket.
The workshop will take place
virtually, with remote participation
from both presenters and attendees. The
workshop will be open to the public and
there is no fee for attendance.
Information will also be posted on the
Calendar of Events on the Commission’s
website, www.ferc.gov, prior to the
event.
The workshop will be transcribed and
webcast. Transcripts will be available
for a fee from Ace Reporting (202–347–
3700). A free webcast of this event is
available through the Commission’s
website. Anyone with internet access
who desires to view this event can do
so by navigating to www.ferc.gov’s
Calendar of Events and locating this
event in the Calendar. The Federal
Energy Regulatory Commission provides
technical support for the free webcasts.
Please call (202) 502–8680 or email
customer@ferc.gov if you have any
questions.
Commission workshops are accessible
under section 508 of the Rehabilitation
Act of 1973. For accessibility
accommodations, please send an email
to accessibility@ferc.gov, call toll-free
VerDate Sep<11>2014
17:51 Dec 05, 2022
Jkt 259001
(866) 208–3372 (voice) or (202) 208–
8659 (TTY), or send a fax to (202) 208–
2106 with the required
accommodations.
For more information about this
workshop, please contact Jessica
Cockrell at jessica.cockrell@ferc.gov or
(202) 502–8190. For information related
to logistics, please contact Sarah
McKinley at sarah.mckinley@ferc.gov or
(202) 502–8368.
Dated: November 30, 2022.
Kimberly D. Bose,
Secretary.
Staff-Led Workshop Establishing
Interregional Transfer Capability
Transmission Planning and Cost
Allocation Requirements, Docket No.
AD23–3–000, December 5–6, 2022
Agenda and Speakers
Background
To aid in our discussion at the
workshop, we will use the following
terms:
• For this discussion, the definition
of Interregional Transfer Capability is
consistent with total transfer capability
as defined in the Commission’s
regulations: ‘‘the amount of electric
power that can be moved or transferred
reliably from one area to another area of
the interconnected transmission systems
by way of all transmission lines (or
paths) between those areas under
specified system conditions, or such
definition as contained in Commissionapproved Reliability Standards.’’ 18
CFR 37.6(b)(1)(vi) (2021). In the context
of Interregional Transfer Capability, an
‘‘area’’ in the above definition would be
a transmission planning region
PO 00000
Frm 00019
Fmt 4703
Sfmt 4703
AD22–13–000.
EL22–83–000.
EL21–85–000, EL21–103–000.
ER22–2690–000, ER22–2690–001.
ER19–2105–005.
EL21–39–000.
ER22–1105–000.
ER22–1606–000.
ER22–1846–000.
composed of public utility transmission
providers.
• For this discussion, Transfer
Transmission Facility is defined as a
transmission facility that increases the
amount of electric power that can be
moved or transferred reliably from one
transmission planning region to another
by way of all transmission lines (or
paths) between those transmission
planning regions. For purposes of
geographic location, a Transfer
Transmission Facility may be located
entirely within a single transmission
planning region (i.e., either a local
transmission facility or a regional
transmission facility), or it may span
two or more transmission planning
regions (i.e., an interregional
transmission facility).
Day One: Monday, December 5, 2022
12:00 p.m.–12:10 p.m.: Welcome and
Opening Remarks
12:10 p.m.–12:25 p.m.: Presentation
from Dr. Dev Millstein, Research
Scientist, Lawrence Berkeley
National Lab, Empirical Estimates
of Transmission Value using
Locational Marginal Prices
12:25 p.m.–2:25 p.m.: Panel 1:
Determining the Need for
Additional Interregional Transfer
Capability
This panel will explore whether the
existing transmission planning and cost
allocation and the interregional
coordination and cost allocation
processes adequately consider the need
to establish a minimum requirement for
Interregional Transfer Capability
between neighboring transmission
planning regions. In addition, the panel
E:\FR\FM\06DEN1.SGM
06DEN1
74614
Federal Register / Vol. 87, No. 233 / Tuesday, December 6, 2022 / Notices
will discuss the specific drivers that
may necessitate the establishment of a
minimum requirement.
This panel may include a discussion
of the following topics:
1. What are the current levels of
Interregional Transfer Capability
between transmission planning regions?
Is more Interregional Transfer Capability
between transmission planning regions
needed? Why or why not?
2. Is the potential need for additional
Interregional Transfer Capability
currently considered in any
transmission planning processes and if
so, how? To the extent such needs are
considered, have they resulted in the
development of any transmission
facilities?
3. What are the drivers of the need for
increasing Interregional Transfer
Capability? To what extent do these
vary based on regional and system
characteristics (e.g., weather patterns,
load diversity, resource mix, etc.)? Are
there barriers to identifying or assessing
these drivers?
4. Is a minimum amount of
Interregional Transfer Capability
between transmission planning regions
necessary to ensure just and reasonable
Commission-jurisdictional rates? If so,
what evidence is there to support, or
negate, that position? How will
planning for a minimum amount of
Interregional Transfer Capability
produce just and reasonable rates?
5. Does the potential need for a
minimum amount of Interregional
Transfer Capability differ between RTO
and non-RTO regions? Why or why not?
Is a minimum amount of Interregional
Transfer Capability necessary for nonRTO regions?
lotter on DSK11XQN23PROD with NOTICES1
Panelists
• Neil Millar, Vice President,
Infrastructure and Operations
Planning, California Independent
System Operator Corporation
• Liza Reed, Ph.D., Research Manager,
Electricity Transmission, Niskanen
Center
• Michele Kito, Supervisor, Electric
Market Design Section, California
Public Utilities Commission
• Philip D. Moeller, Executive Vice
President, Edison Electric Institute
• Tricia Pridemore, Chairman, Georgia
Public Service Commission
• Simon Mahan, Executive Director,
Southern Renewable Energy
Association
2:25 p.m.–2:45 p.m.: Break
2:45 p.m.–3:00 p.m.: Presentation from
Dr. Adria Brooks, U.S. Department
of Energy Grid Deployment Office,
Transmission Division
VerDate Sep<11>2014
17:51 Dec 05, 2022
Jkt 259001
3:00 p.m.–4:55 p.m.: Panel 2:
Considerations for Establishing
Potential Interregional Transfer
Capability Requirements
This panel will discuss who would be
responsible for determining a minimum
Interregional Transfer Capability
requirement and the relevant
considerations for establishing such a
requirement, assuming that there is such
a need. Specifically, this panel will
focus on identifying the objective, and
drivers, of a minimum Interregional
Transfer Capability requirement. This
panel may include a discussion of the
following topics:
1. What principles should be used to
establish a minimum amount of
Interregional Transfer Capability (e.g.,
should a minimum Interregional
Transfer Capability requirement be
determined based on the cost impact to
transmission customers during extreme
events, such as extreme weather, widespread loss of fuel supply, etc.)?
2. To what extent, if any, should the
following be considered when
establishing a minimum Interregional
Transfer Capability requirement?
a. Historical or projected extreme
events (e.g., extreme weather, loss of
fuel supply, etc.)
b. Load and resource diversity across
a wide geographic area
c. Anticipated changes in the resource
mix and demand
d. Improved reliability
e. Avoided production costs
f. Geographic zones with the potential
for large amounts of new generation
g. The option value of Transfer
Transmission Facilities, as determined
by the increased access to supplemental
capacity during emergency operating
conditions.
h. Increased operator flexibility
i. Others?
3. Should planning criteria other than
reliability and resilience be considered
in establishing a minimum Interregional
Transfer Capability requirement?
4. For this question, please consider:
(a) public utility transmission providers
in each pair of neighboring transmission
planning regions, (b) the public utility
transmission providers in all of a
transmission planning region’s
neighboring transmission planning
regions, and (c) all public utility
transmission providers within an
Interconnection.
a. What role should the Commission,
relevant groupings of public utility
transmission providers described in (a),
(b), and (c) above, or other relevant
entities play in determining what, if
any, minimum amount of Interregional
Transfer Capability is needed? What are
PO 00000
Frm 00020
Fmt 4703
Sfmt 4703
the advantages and disadvantages of
each approach?
b. Should the Commission establish a
specific formula or planning process, or
instead more general criteria,
guidelines, or principles for public
utility transmission providers to follow
in establishing a minimum Interregional
Transfer Capability? Should the
Commission allow public utility
transmission providers flexibility in
whether to work on a bilateral basis
with neighboring regions, or require
planning to be carried out across a
broader geography? What are the
advantages and disadvantages of each
approach?
c. Should the principles considered
be consistent for (a), (b) or (c) above?
What are the advantages and
disadvantages of each approach?
5. How should merchant transmission
facility developers and public utility
transmission providers conducting
transmission planning avoid planning
duplicative or conflicting transmission
facilities to increase Interregional
Transfer Capability?
6. To what extent, if at all, would a
minimum Interregional Transfer
Capability requirement complement or
conflict with a potential new or
modified NERC Reliability Standard
that requires consideration of extreme
heat and cold events as proposed in
Docket No. RM22–10?
7. Should the establishment of a
minimum amount of Interregional
Transfer Capability for non-RTO regions
differ from that for RTO regions? If so,
how?
Panelists
• Debra Lew, Ph.D., Associate Director,
Energy System Integration Group
• Aaron Bloom, Executive Director,
NextEra Energy Transmission, LLC
• Laura Rauch, Senior Director,
Transmission Planning, Midcontinent
Independent System Operator, Inc.
• David Kelley, Director of Seams and
Tariff Services, Southwest Power
Pool, Inc.
• Saad Malik, Director Reliability
Planning, Western Electricity
Coordinating Council
• Deral Danis, Senior Director,
Transmission, Pattern Energy Group
LP
• Sharon Segner, Senior Vice President
of Transmission Policy, LS Power
Development, LLC
4:55 p.m.–5:00 p.m.: Closing Remarks
llllllllllllllllll
Day Two: Tuesday, December 6, 2022
12:00 p.m.–12:10 p.m.: Welcome and
Opening Remarks
E:\FR\FM\06DEN1.SGM
06DEN1
lotter on DSK11XQN23PROD with NOTICES1
Federal Register / Vol. 87, No. 233 / Tuesday, December 6, 2022 / Notices
12:10 p.m.–2:15 p.m.: Panel 3: Process
for Establishing Potential
Interregional Transfer Capability
Requirements
This panel will discuss the process for
determining a minimum amount of
Interregional Transfer Capability
including, but not limited to, the
determination of key data inputs,
modeling techniques, and relevant
metrics.
This panel may include a discussion
of the following topics:
1. What process should be used to
determine a minimum amount of
Interregional Transfer Capability? For
example, should the minimum be (a)
derived heuristically from past extreme
events; (b) derived using a probabilistic
approach; or (c) based on scenario
planning similar to the requirements
proposed for Long-Term Regional
Transmission Planning (Docket No.
RM21–17–000) or other deterministic
analysis? What are the advantages and
disadvantages of each approach?
a. With respect to a probabilistic
approach, what are the primary
challenges in developing probabilistic
models to determine a minimum
amount of Interregional Transfer
Capability? Do current probabilistic
methods model common mode outages
appropriately? If not, to what extent
does that reduce the usefulness of a
probabilistic approach?
b. With respect to scenario planning
to determine a minimum amount of
Interregional Transfer Capability, what
guidelines, if any, are necessary to
ensure that such scenario planning
adequately assesses the need for, and
value of, increased Interregional
Transfer Capability? Are certain types of
scenarios particularly important to
assess the need for, and value of,
Interregional Transfer Capability?
Should scenario planning account for
wide-area events and correlated outages,
and if so, how?
2. After a need for a minimum amount
of Interregional Transfer Capability is
determined, what models and data are
necessary to evaluate it? Do public
utility transmission providers typically
have access to or collect these models
and data? If not, how should public
utility transmission providers acquire
these models and data? To simulate the
wide-area impact of extreme events, to
what extent should these models and
data represent the overall
interconnection?
3. What criteria should be used to
assess whether public utility
transmission providers have sufficient
existing transmission facilities to meet
or surpass an Interregional Transfer
VerDate Sep<11>2014
17:51 Dec 05, 2022
Jkt 259001
Capability requirement? Please specify
whether your answer to this question
depends on your answer to question 1
in this panel.
a. Is there a benefit to using a specific
metric of Interregional Transfer
Capability? Potential metrics may
include a set amount of electric power,
an amount of electric power relative to
some electric power characteristic of the
transmission planning region (like peak
load, or the largest single contingency),
among others.
b. To what extent should public
utility transmission providers in a
transmission planning region consider
criteria that would help ensure the
‘‘right amount’’ of Interregional Transfer
Capability is identified and sufficient
Transfer Transmission Facilities are
selected to meet an Interregional
Transfer Capability requirement? For
example, should the criteria used to
assess whether public utility
transmission providers meet an
Interregional Transfer Capability
requirement be informed by the netbenefits, or other types of measures, of
Transfer Transmission Facilities?
4. What operational barriers preclude
potential Interregional Transfer
Capability from being realized during
normal and emergency system
conditions?
Panelists
• Sheila Manz, Ph.D., Technical
Director, Decarbonization Planning,
GE Energy Consulting
• Digaunto Chatterjee, Vice President,
System Planning, Eversource Energy
• David Souder, Executive Director,
System Planning, PJM
Interconnection, L.L.C. and Vice
Chair, Eastern Interconnection
Planning Collaborative Technical
Committee
• Michael Goggin, Vice President, Grid
Strategies, LLC, speaking on behalf of
the American Clean Power
Association
• Nicolas Koehler, Director,
Transmission Planning, American
Electric Power Company
• Christopher Clack, Ph.D., Chief
Executive Officer, Vibrant Clean
Energy, LLC
2:15 p.m.–2:30 p.m.: Break
2:30 p.m.–4:45 p.m.: Panel 4: Meeting
the Goal of Increased Interregional
Transfer Capability
This panel will discuss how costs for
Transfer Transmission Facilities should
be allocated and how to ensure a
minimum amount of Interregional
Transfer Capability is achieved and
maintained.
This panel may include a discussion
of the following topics:
PO 00000
Frm 00021
Fmt 4703
Sfmt 4703
74615
1. How should cost allocation for
Transfer Transmission Facilities be
determined? For example, should public
utility transmission providers in a
transmission planning region be
required to allocate the costs of Transfer
Transmission Facilities: (1) within their
own transmission planning region; (2)
jointly with two or more neighboring
transmission planning regions; (3) at an
Interconnection-wide level; or (4) via
some other process? What are the
advantages or disadvantages of each
approach? Should there be a process in
place for the Commission to establish a
cost allocation method for Transfer
Transmission Facilities if the public
utility transmission providers in (1), (2),
or (3) above cannot agree?
a. How should the process for
evaluating, selecting, and allocating the
costs of Transfer Transmission Facilities
align with current regional transmission
planning and interregional transmission
coordination processes (e.g., should the
process be a part of existing
transmission planning and cost
allocation and/or coordination and cost
allocation processes or should it be a
separate process)?
2. How would public utility
transmission providers in a
transmission planning region
demonstrate that they have met the
minimum Interregional Transfer
Capability requirement?
3. What process would public utility
transmission providers in (a) a
transmission planning region, (b) a pair
of transmission planning regions, or (c)
a broader collection of neighboring
planning regions use to identify and
select Transfer Transmission Facilities?
4. Should the Commission reexamine
the minimum Interregional Transfer
Capability requirement or the required
process to identify and select Transfer
Transmission Facilities at some point in
the future (e.g., in 10 years)?
5. What, if any, categories of benefits
should public utility transmission
providers be required to consider when
evaluating Transfer Transmission
Facilities for selection for purposes of
cost allocation?
a. Should the benefits considered be
consistent between (a) public utility
transmission providers in each pair of
neighboring transmission planning
regions, (b) the public utility
transmission providers in all of a
transmission planning region’s
neighboring transmission planning
regions, or (c) all public utility
transmission providers within an
Interconnection? What are the
advantages and disadvantages of each
approach?
E:\FR\FM\06DEN1.SGM
06DEN1
74616
Federal Register / Vol. 87, No. 233 / Tuesday, December 6, 2022 / Notices
6. Should the Commission prescribe a
standard, or principles to govern the
selection of Transfer Transmission
Facilities for purposes of cost
allocation?
7. Should the Commission require
public utility transmission providers to
use a portfolio approach for selecting
Transfer Transmission Facilities to meet
a minimum amount of Interregional
Transfer Capability?
8. What rules, if any, should the
Commission promulgate with regard to
establishing a cost allocation method for
Transfer Transmission Facilities?
a. What are the advantages and
disadvantages of the Commission
requiring a specific ex ante regional
and/or interregional cost allocation
method for Transfer Transmission
Facilities?
b. What are the advantages and
disadvantages of the Commission
requiring a specific ex post regional
and/or interregional cost allocation
method or a hybrid (i.e., part ex ante
and part ex post) for Transfer
Transmission Facilities?
c. Should the Commission decline to
prescribe an ex ante or ex post cost
allocation method for applicable public
utility transmission providers, what
process should govern the establishment
of cost allocation rules for any particular
Transfer Transmission Facility?
9. What role should state and local
governmental entities play in the public
utility transmission provider process for
selection and cost allocation for
Transfer Transmission Facilities?
Should the states’ role in selection and
cost allocation be determined by the
drivers of the need for a minimum
requirement for Transfer Transmission
Facilities? For example, if the Transfer
Transmission Facilities are planned to
serve public policy goals, such as
renewable generation deployment,
should the states have a role in cost
allocation, such as that proposed in the
Notice of Proposed Rulemaking in
RM21–17?
10. Are there barriers to the ability of
interregional merchant transmission
facilities in providing a minimum
amount of Interregional Transfer
Capability? For example, do contractual
or tariff limitations prevent merchant
interregional high-voltage direct current
transmission facilities from supporting
reliability during extreme events?
Panelists
• Kris Zadlo, Chief Development
Officer, Grid United
• Travis Kavulla, Vice President
Regulatory Affairs, NRG Energy, Inc.
• Shashank Sane, Executive Vice
President, Transmission, Invenergy
• Rob Gramlich, Founder and
President, Grid Strategies, LLC
• Andrew French, Commissioner,
Kansas Corporation Commission
• J. Arnold Quinn, Chief Economist,
Vistra Corp.
4:45 p.m.–5:00 p.m.: Closing Remarks
[FR Doc. 2022–26474 Filed 12–5–22; 8:45 am]
BILLING CODE 6717–01–P
FEDERAL DEPOSIT INSURANCE
CORPORATION
Notice of Termination of Receiverships
The Federal Deposit Insurance
Corporation (FDIC or Receiver), as
Receiver for each of the following
insured depository institutions, was
charged with the duty of winding up the
affairs of the former institutions and
liquidating all related assets. The
Receiver has fulfilled its obligations and
made all dividend distributions
required by law.
NOTICE OF TERMINATION OF RECEIVERSHIPS
Fund
lotter on DSK11XQN23PROD with NOTICES1
10005
10012
10037
10061
10131
10220
10330
10336
10531
................
................
................
................
................
................
................
................
................
Receivership name
City
ANB Financial, NA ..........................................................................
Integrity Bank ..................................................................................
Corn Belt Bank & Trust Company ..................................................
Bankunited, FSB .............................................................................
Hillcrest Bank Florida .....................................................................
Citizens Bank & Trust Company of Chicago .................................
The Bank of Asheville ....................................................................
American Trust Bank ......................................................................
THE Enloe State Bank ...................................................................
Bentonville ..................................
Alpharetta ...................................
Pittsfield ......................................
Coral Gables ..............................
Naples ........................................
Chicago ......................................
Asheville .....................................
Roswell .......................................
Cooper .......................................
The Receiver has further irrevocably
authorized and appointed FDICCorporate as its attorney-in-fact to
execute and file any and all documents
that may be required to be executed by
the Receiver which FDIC-Corporate, in
its sole discretion, deems necessary,
including but not limited to releases,
discharges, satisfactions, endorsements,
assignments, and deeds. Effective on the
termination dates listed above, the
Receiverships have been terminated, the
Receiver has been discharged, and the
Receiverships have ceased to exist as
legal entities.
Dated at Washington, DC, on December 1,
2022.
James P. Sheesley,
Assistant Executive Secretary.
ACTION:
[FR Doc. 2022–26505 Filed 12–5–22; 8:45 am]
SUMMARY:
BILLING CODE 6714–01–P
FEDERAL HOUSING FINANCE
AGENCY
[No. 2022–N–15]
(Authority: 12 U.S.C. 1819)
Proposed Collection; Comment
Request
Federal Deposit Insurance Corporation.
AGENCY:
Federal Housing Finance
Agency.
VerDate Sep<11>2014
17:51 Dec 05, 2022
Jkt 259001
State
PO 00000
Frm 00022
Fmt 4703
Sfmt 4703
AR
GA
IL
FL
FL
IL
NC
GA
TX
Termination
date
12/01/2022
12/01/2022
12/01/2022
12/01/2022
12/01/2022
12/01/2022
12/01/2022
12/01/2022
12/01/2022
60-Day notice of submission of
information collection for approval from
Office of Management and Budget.
In accordance with the
requirements of the Paperwork
Reduction Act of 1995 (PRA), the
Federal Housing Finance Agency
(FHFA) is seeking public comments
concerning an information collection
known as the ‘‘National Survey of
Mortgage Originations’’ (NSMO), which
has been assigned control number 2590–
0012 by the Office of Management and
Budget (OMB). FHFA intends to submit
the information collection to OMB for
review and approval of a three-year
extension of the control number, which
is due to expire on June 30, 2023.
E:\FR\FM\06DEN1.SGM
06DEN1
]]>Agencies
[Federal Register Volume 87, Number 233 (Tuesday, December 6, 2022)]
[Notices]
[Pages 74612-74616]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2022-26474]
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Docket No. AD23-3-000]
Establishing Interregional Transfer Capability Transmission
Planning and Cost Allocation Requirements; Supplemental Notice of
Staff-Led Workshop
As announced in the Notice of Staff-Led Workshop issued in this
proceeding on October 6, 2022, Federal Energy Regulatory Commission
(Commission) staff will convene a workshop to discuss whether and how
the Commission could establish a minimum requirement for Interregional
Transfer Capability for public utility transmission providers in
transmission planning and cost allocation processes on December 5 and
6, 2022, from approximately 12:00 p.m. to 5:00 p.m. Eastern Time.
The purpose of this workshop is to consider the question of whether
and how to establish a minimum requirement for Interregional Transfer
[[Page 74613]]
Capability. Topics for discussion may include: how to determine the
need for and benefit of setting a minimum requirement for Interregional
Transfer Capability; what to consider in establishing a potential
Interregional Transfer Capability requirement, including who would be
responsible for determining a minimum Interregional Transfer Capability
requirement and what would be the objective and drivers of such a
requirement; what process could be used in establishing a minimum
Interregional Transfer Capability requirement to determine key data
inputs, modeling techniques, and relevant metrics; and how costs for
transmission facilities intended to increase Interregional Transfer
Capability should be allocated and how to ensure a minimum amount of
Interregional Transfer Capability is achieved and maintained.
While the workshop is not for the purpose of discussing any
specific matters before the Commission, some workshop discussions may
involve issues raised in proceedings that are currently pending before
the Commission. These proceedings include, but are not limited to:
------------------------------------------------------------------------
Docket Nos.
------------------------------------------------------------------------
Invenergy Transmission LLC................. AD22-13-000.
Invenergy Transmission LLC v. Midcontinent EL22-83-000.
Independent System Operator, Inc.
SOO Green HVDC Link ProjectCo, LLC v. PJM EL21-85-000, EL21-103-000.
Interconnection, LLC.
PPL Electric Utilities Corporation, PJM ER22-2690-000, ER22-2690-
Interconnection, L.L.C. 001.
Appalachian Power Company, PJM ER19-2105-005.
Interconnection, L.L.C.
Neptune Regional Transmission System, LLC EL21-39-000.
and Long Island Power Authority v. PJM
Interconnection, L.L.C.
WestConnect Public Utilities............... ER22-1105-000.
PPL Electric Utilities Corporation......... ER22-1606-000.
Southwest Power Pool, Inc.................. ER22-1846-000.
------------------------------------------------------------------------
Attached to this Supplemental Notice is an agenda for the workshop,
which includes the workshop program and expected panelists.
Panelists are asked to submit advance materials to provide any
information related to their respective panel (e.g., summary
statements, reports, whitepapers, studies, or testimonies) that
panelists believe should be included in the record of this proceeding
by November 21, 2022. Panelists should file all advance materials in
the AD23-3-000 docket.
The workshop will take place virtually, with remote participation
from both presenters and attendees. The workshop will be open to the
public and there is no fee for attendance. Information will also be
posted on the Calendar of Events on the Commission's website,
www.ferc.gov, prior to the event.
The workshop will be transcribed and webcast. Transcripts will be
available for a fee from Ace Reporting (202-347-3700). A free webcast
of this event is available through the Commission's website. Anyone
with internet access who desires to view this event can do so by
navigating to www.ferc.gov's Calendar of Events and locating this event
in the Calendar. The Federal Energy Regulatory Commission provides
technical support for the free webcasts. Please call (202) 502-8680 or
email [email protected] if you have any questions.
Commission workshops are accessible under section 508 of the
Rehabilitation Act of 1973. For accessibility accommodations, please
send an email to [email protected], call toll-free (866) 208-3372
(voice) or (202) 208-8659 (TTY), or send a fax to (202) 208-2106 with
the required accommodations.
For more information about this workshop, please contact Jessica
Cockrell at [email protected] or (202) 502-8190. For
information related to logistics, please contact Sarah McKinley at
[email protected] or (202) 502-8368.
Dated: November 30, 2022.
Kimberly D. Bose,
Secretary.
Staff-Led Workshop Establishing Interregional Transfer Capability
Transmission Planning and Cost Allocation Requirements, Docket No.
AD23-3-000, December 5-6, 2022
Agenda and Speakers
Background
To aid in our discussion at the workshop, we will use the following
terms:
For this discussion, the definition of Interregional
Transfer Capability is consistent with total transfer capability as
defined in the Commission's regulations: ``the amount of electric power
that can be moved or transferred reliably from one area to another area
of the interconnected transmission systems by way of all transmission
lines (or paths) between those areas under specified system conditions,
or such definition as contained in Commission-approved Reliability
Standards.'' 18 CFR 37.6(b)(1)(vi) (2021). In the context of
Interregional Transfer Capability, an ``area'' in the above definition
would be a transmission planning region composed of public utility
transmission providers.
For this discussion, Transfer Transmission Facility is
defined as a transmission facility that increases the amount of
electric power that can be moved or transferred reliably from one
transmission planning region to another by way of all transmission
lines (or paths) between those transmission planning regions. For
purposes of geographic location, a Transfer Transmission Facility may
be located entirely within a single transmission planning region (i.e.,
either a local transmission facility or a regional transmission
facility), or it may span two or more transmission planning regions
(i.e., an interregional transmission facility).
Day One: Monday, December 5, 2022
12:00 p.m.-12:10 p.m.: Welcome and Opening Remarks
12:10 p.m.-12:25 p.m.: Presentation from Dr. Dev Millstein, Research
Scientist, Lawrence Berkeley National Lab, Empirical Estimates of
Transmission Value using Locational Marginal Prices
12:25 p.m.-2:25 p.m.: Panel 1: Determining the Need for Additional
Interregional Transfer Capability
This panel will explore whether the existing transmission planning
and cost allocation and the interregional coordination and cost
allocation processes adequately consider the need to establish a
minimum requirement for Interregional Transfer Capability between
neighboring transmission planning regions. In addition, the panel
[[Page 74614]]
will discuss the specific drivers that may necessitate the
establishment of a minimum requirement.
This panel may include a discussion of the following topics:
1. What are the current levels of Interregional Transfer Capability
between transmission planning regions? Is more Interregional Transfer
Capability between transmission planning regions needed? Why or why
not?
2. Is the potential need for additional Interregional Transfer
Capability currently considered in any transmission planning processes
and if so, how? To the extent such needs are considered, have they
resulted in the development of any transmission facilities?
3. What are the drivers of the need for increasing Interregional
Transfer Capability? To what extent do these vary based on regional and
system characteristics (e.g., weather patterns, load diversity,
resource mix, etc.)? Are there barriers to identifying or assessing
these drivers?
4. Is a minimum amount of Interregional Transfer Capability between
transmission planning regions necessary to ensure just and reasonable
Commission-jurisdictional rates? If so, what evidence is there to
support, or negate, that position? How will planning for a minimum
amount of Interregional Transfer Capability produce just and reasonable
rates?
5. Does the potential need for a minimum amount of Interregional
Transfer Capability differ between RTO and non-RTO regions? Why or why
not? Is a minimum amount of Interregional Transfer Capability necessary
for non-RTO regions?
Panelists
Neil Millar, Vice President, Infrastructure and Operations
Planning, California Independent System Operator Corporation
Liza Reed, Ph.D., Research Manager, Electricity Transmission,
Niskanen Center
Michele Kito, Supervisor, Electric Market Design Section,
California Public Utilities Commission
Philip D. Moeller, Executive Vice President, Edison Electric
Institute
Tricia Pridemore, Chairman, Georgia Public Service Commission
Simon Mahan, Executive Director, Southern Renewable Energy
Association
2:25 p.m.-2:45 p.m.: Break
2:45 p.m.-3:00 p.m.: Presentation from Dr. Adria Brooks, U.S.
Department of Energy Grid Deployment Office, Transmission Division
3:00 p.m.-4:55 p.m.: Panel 2: Considerations for Establishing Potential
Interregional Transfer Capability Requirements
This panel will discuss who would be responsible for determining a
minimum Interregional Transfer Capability requirement and the relevant
considerations for establishing such a requirement, assuming that there
is such a need. Specifically, this panel will focus on identifying the
objective, and drivers, of a minimum Interregional Transfer Capability
requirement. This panel may include a discussion of the following
topics:
1. What principles should be used to establish a minimum amount of
Interregional Transfer Capability (e.g., should a minimum Interregional
Transfer Capability requirement be determined based on the cost impact
to transmission customers during extreme events, such as extreme
weather, wide-spread loss of fuel supply, etc.)?
2. To what extent, if any, should the following be considered when
establishing a minimum Interregional Transfer Capability requirement?
a. Historical or projected extreme events (e.g., extreme weather,
loss of fuel supply, etc.)
b. Load and resource diversity across a wide geographic area
c. Anticipated changes in the resource mix and demand
d. Improved reliability
e. Avoided production costs
f. Geographic zones with the potential for large amounts of new
generation
g. The option value of Transfer Transmission Facilities, as
determined by the increased access to supplemental capacity during
emergency operating conditions.
h. Increased operator flexibility
i. Others?
3. Should planning criteria other than reliability and resilience
be considered in establishing a minimum Interregional Transfer
Capability requirement?
4. For this question, please consider: (a) public utility
transmission providers in each pair of neighboring transmission
planning regions, (b) the public utility transmission providers in all
of a transmission planning region's neighboring transmission planning
regions, and (c) all public utility transmission providers within an
Interconnection.
a. What role should the Commission, relevant groupings of public
utility transmission providers described in (a), (b), and (c) above, or
other relevant entities play in determining what, if any, minimum
amount of Interregional Transfer Capability is needed? What are the
advantages and disadvantages of each approach?
b. Should the Commission establish a specific formula or planning
process, or instead more general criteria, guidelines, or principles
for public utility transmission providers to follow in establishing a
minimum Interregional Transfer Capability? Should the Commission allow
public utility transmission providers flexibility in whether to work on
a bilateral basis with neighboring regions, or require planning to be
carried out across a broader geography? What are the advantages and
disadvantages of each approach?
c. Should the principles considered be consistent for (a), (b) or
(c) above? What are the advantages and disadvantages of each approach?
5. How should merchant transmission facility developers and public
utility transmission providers conducting transmission planning avoid
planning duplicative or conflicting transmission facilities to increase
Interregional Transfer Capability?
6. To what extent, if at all, would a minimum Interregional
Transfer Capability requirement complement or conflict with a potential
new or modified NERC Reliability Standard that requires consideration
of extreme heat and cold events as proposed in Docket No. RM22-10?
7. Should the establishment of a minimum amount of Interregional
Transfer Capability for non-RTO regions differ from that for RTO
regions? If so, how?
Panelists
Debra Lew, Ph.D., Associate Director, Energy System
Integration Group
Aaron Bloom, Executive Director, NextEra Energy Transmission,
LLC
Laura Rauch, Senior Director, Transmission Planning,
Midcontinent Independent System Operator, Inc.
David Kelley, Director of Seams and Tariff Services, Southwest
Power Pool, Inc.
Saad Malik, Director Reliability Planning, Western Electricity
Coordinating Council
Deral Danis, Senior Director, Transmission, Pattern Energy
Group LP
Sharon Segner, Senior Vice President of Transmission Policy,
LS Power Development, LLC
4:55 p.m.-5:00 p.m.: Closing Remarks
-----------------------------------------------------------------------
Day Two: Tuesday, December 6, 2022
12:00 p.m.-12:10 p.m.: Welcome and Opening Remarks
[[Page 74615]]
12:10 p.m.-2:15 p.m.: Panel 3: Process for Establishing Potential
Interregional Transfer Capability Requirements
This panel will discuss the process for determining a minimum
amount of Interregional Transfer Capability including, but not limited
to, the determination of key data inputs, modeling techniques, and
relevant metrics.
This panel may include a discussion of the following topics:
1. What process should be used to determine a minimum amount of
Interregional Transfer Capability? For example, should the minimum be
(a) derived heuristically from past extreme events; (b) derived using a
probabilistic approach; or (c) based on scenario planning similar to
the requirements proposed for Long-Term Regional Transmission Planning
(Docket No. RM21-17-000) or other deterministic analysis? What are the
advantages and disadvantages of each approach?
a. With respect to a probabilistic approach, what are the primary
challenges in developing probabilistic models to determine a minimum
amount of Interregional Transfer Capability? Do current probabilistic
methods model common mode outages appropriately? If not, to what extent
does that reduce the usefulness of a probabilistic approach?
b. With respect to scenario planning to determine a minimum amount
of Interregional Transfer Capability, what guidelines, if any, are
necessary to ensure that such scenario planning adequately assesses the
need for, and value of, increased Interregional Transfer Capability?
Are certain types of scenarios particularly important to assess the
need for, and value of, Interregional Transfer Capability? Should
scenario planning account for wide-area events and correlated outages,
and if so, how?
2. After a need for a minimum amount of Interregional Transfer
Capability is determined, what models and data are necessary to
evaluate it? Do public utility transmission providers typically have
access to or collect these models and data? If not, how should public
utility transmission providers acquire these models and data? To
simulate the wide-area impact of extreme events, to what extent should
these models and data represent the overall interconnection?
3. What criteria should be used to assess whether public utility
transmission providers have sufficient existing transmission facilities
to meet or surpass an Interregional Transfer Capability requirement?
Please specify whether your answer to this question depends on your
answer to question 1 in this panel.
a. Is there a benefit to using a specific metric of Interregional
Transfer Capability? Potential metrics may include a set amount of
electric power, an amount of electric power relative to some electric
power characteristic of the transmission planning region (like peak
load, or the largest single contingency), among others.
b. To what extent should public utility transmission providers in a
transmission planning region consider criteria that would help ensure
the ``right amount'' of Interregional Transfer Capability is identified
and sufficient Transfer Transmission Facilities are selected to meet an
Interregional Transfer Capability requirement? For example, should the
criteria used to assess whether public utility transmission providers
meet an Interregional Transfer Capability requirement be informed by
the net-benefits, or other types of measures, of Transfer Transmission
Facilities?
4. What operational barriers preclude potential Interregional
Transfer Capability from being realized during normal and emergency
system conditions?
Panelists
Sheila Manz, Ph.D., Technical Director, Decarbonization
Planning, GE Energy Consulting
Digaunto Chatterjee, Vice President, System Planning,
Eversource Energy
David Souder, Executive Director, System Planning, PJM
Interconnection, L.L.C. and Vice Chair, Eastern Interconnection
Planning Collaborative Technical Committee
Michael Goggin, Vice President, Grid Strategies, LLC, speaking
on behalf of the American Clean Power Association
Nicolas Koehler, Director, Transmission Planning, American
Electric Power Company
Christopher Clack, Ph.D., Chief Executive Officer, Vibrant
Clean Energy, LLC
2:15 p.m.-2:30 p.m.: Break
2:30 p.m.-4:45 p.m.: Panel 4: Meeting the Goal of Increased
Interregional Transfer Capability
This panel will discuss how costs for Transfer Transmission
Facilities should be allocated and how to ensure a minimum amount of
Interregional Transfer Capability is achieved and maintained.
This panel may include a discussion of the following topics:
1. How should cost allocation for Transfer Transmission Facilities
be determined? For example, should public utility transmission
providers in a transmission planning region be required to allocate the
costs of Transfer Transmission Facilities: (1) within their own
transmission planning region; (2) jointly with two or more neighboring
transmission planning regions; (3) at an Interconnection-wide level; or
(4) via some other process? What are the advantages or disadvantages of
each approach? Should there be a process in place for the Commission to
establish a cost allocation method for Transfer Transmission Facilities
if the public utility transmission providers in (1), (2), or (3) above
cannot agree?
a. How should the process for evaluating, selecting, and allocating
the costs of Transfer Transmission Facilities align with current
regional transmission planning and interregional transmission
coordination processes (e.g., should the process be a part of existing
transmission planning and cost allocation and/or coordination and cost
allocation processes or should it be a separate process)?
2. How would public utility transmission providers in a
transmission planning region demonstrate that they have met the minimum
Interregional Transfer Capability requirement?
3. What process would public utility transmission providers in (a)
a transmission planning region, (b) a pair of transmission planning
regions, or (c) a broader collection of neighboring planning regions
use to identify and select Transfer Transmission Facilities?
4. Should the Commission reexamine the minimum Interregional
Transfer Capability requirement or the required process to identify and
select Transfer Transmission Facilities at some point in the future
(e.g., in 10 years)?
5. What, if any, categories of benefits should public utility
transmission providers be required to consider when evaluating Transfer
Transmission Facilities for selection for purposes of cost allocation?
a. Should the benefits considered be consistent between (a) public
utility transmission providers in each pair of neighboring transmission
planning regions, (b) the public utility transmission providers in all
of a transmission planning region's neighboring transmission planning
regions, or (c) all public utility transmission providers within an
Interconnection? What are the advantages and disadvantages of each
approach?
[[Page 74616]]
6. Should the Commission prescribe a standard, or principles to
govern the selection of Transfer Transmission Facilities for purposes
of cost allocation?
7. Should the Commission require public utility transmission
providers to use a portfolio approach for selecting Transfer
Transmission Facilities to meet a minimum amount of Interregional
Transfer Capability?
8. What rules, if any, should the Commission promulgate with regard
to establishing a cost allocation method for Transfer Transmission
Facilities?
a. What are the advantages and disadvantages of the Commission
requiring a specific ex ante regional and/or interregional cost
allocation method for Transfer Transmission Facilities?
b. What are the advantages and disadvantages of the Commission
requiring a specific ex post regional and/or interregional cost
allocation method or a hybrid (i.e., part ex ante and part ex post) for
Transfer Transmission Facilities?
c. Should the Commission decline to prescribe an ex ante or ex post
cost allocation method for applicable public utility transmission
providers, what process should govern the establishment of cost
allocation rules for any particular Transfer Transmission Facility?
9. What role should state and local governmental entities play in
the public utility transmission provider process for selection and cost
allocation for Transfer Transmission Facilities? Should the states'
role in selection and cost allocation be determined by the drivers of
the need for a minimum requirement for Transfer Transmission
Facilities? For example, if the Transfer Transmission Facilities are
planned to serve public policy goals, such as renewable generation
deployment, should the states have a role in cost allocation, such as
that proposed in the Notice of Proposed Rulemaking in RM21-17?
10. Are there barriers to the ability of interregional merchant
transmission facilities in providing a minimum amount of Interregional
Transfer Capability? For example, do contractual or tariff limitations
prevent merchant interregional high-voltage direct current transmission
facilities from supporting reliability during extreme events?
Panelists
Kris Zadlo, Chief Development Officer, Grid United
Travis Kavulla, Vice President Regulatory Affairs, NRG Energy,
Inc.
Shashank Sane, Executive Vice President, Transmission,
Invenergy
Rob Gramlich, Founder and President, Grid Strategies, LLC
Andrew French, Commissioner, Kansas Corporation Commission
J. Arnold Quinn, Chief Economist, Vistra Corp.
4:45 p.m.-5:00 p.m.: Closing Remarks
[FR Doc. 2022-26474 Filed 12-5-22; 8:45 am]
BILLING CODE 6717-01-P
