Order 697-C (issued 6/18/2009, as pub. in Fed. Reg. 6/29/2009)

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Subject
(d) Air Transport Association (ATA) of
America Code 55: Stabilizers.
Unsafe Condition
(e) This AD results from a report of cracks
found in the right upper aft skin panel of the
horizontal stabilizer at the aft inboard corner.
We are issuing this AD to detect and correct
cracks in the fail-safe structure that may not
be able to sustain limit load, which could
result in the loss of overall structural
integrity of the horizontal stabilizer.
Compliance
(f) Comply with this AD within the
compliance times specified, unless already
done.
Inspections
(g) Except as required by paragraphs (h)
and (i) of this AD: At the times specified in
paragraph 1.E., ‘‘Compliance,’’ of Boeing
Alert Service Bulletin MD90–55A012, dated
September 23, 2008, do an eddy current
inspection for cracks of the upper aft skin
panels on the left and right sides of the
horizontal stabilizer, and do all applicable
related investigative and corrective actions,
in accordance with the Accomplishment
Instructions of the service bulletin.
Exceptions to Service Bulletin Specifications
(h) Where Boeing Alert Service Bulletin
MD90–55A012, dated September 23, 2008,
specifies a compliance time after the date on
the service bulletin, this AD requires
compliance within the specified compliance
time after the effective date of this AD.
(i) If any crack is found during any
inspection required by this AD, and Boeing
Alert Service Bulletin MD90–55A012, dated
September 23, 2008, specifies to contact
Boeing for appropriate action: Before further
flight, repair using a method approved in
accordance with the procedures specified in
paragraph (k) of this AD.
Inspections Done According to Multiple
Operator Message
(j) Inspections and corrective actions done
before the effective date of this AD are
acceptable for compliance with the
corresponding requirements of this AD, if
done in accordance with Boeing Multiple
Operator Message 1–669017091–1, dated
November 9, 2007.
Alternative Methods of Compliance
(AMOCs)
(k)(1) The Manager, Los Angeles Aircraft
Certification Office, FAA, ATTN: Roger
Durbin, Aerospace Engineer, Airframe
Branch, ANM–120L, FAA, Los Angeles
Aircraft Certification Office, 3960 Paramount
Boulevard, Lakewood, California 90712–
4137; telephone (562) 627–5233; fax (562)

627–5210; has the authority to approve
AMOCs for this AD, if requested using the
procedures found in 14 CFR 39.19.
(2) To request a different method of
compliance or a different compliance time
for this AD, follow the procedures in 14 CFR
39.19. Before using any approved AMOC on
any airplane to which the AMOC applies,
notify your principal maintenance inspector
(PMI) or principal avionics inspector (PAI),
as appropriate, in the FAA Flight Standards
District Office (FSDO), or lacking a principal
inspector, your local FSDO. The AMOC
approval letter must specifically reference
this AD.
(3) An AMOC that provides an acceptable
level of safety may be used for any repair
required by this AD, if it is approved by an
Authorized Representative for the Boeing
Commercial Airplanes Delegation Option
Authorization Organization who has been
authorized by the Manager, Los Angeles
ACO, to make those findings. For a repair
method to be approved, the repair must meet
the certification basis of the airplane and the
approval must specifically refer to this AD.
Material Incorporated by Reference
(l) You must use Boeing Alert Service
Bulletin MD90–55A012, dated September 23,
2008, to do the actions required by this AD,
unless the AD specifies otherwise.
(1) The Director of the Federal Register
approved the incorporation by reference of
this service information under 5 U.S.C.
552(a) and 1 CFR part 51.
(2) For service information identified in
this AD, contact Boeing Commercial
Airplanes, Attention: Data & Services
Management, 3855 Lakewood Boulevard, MC
D800–0019, Long Beach, California 90846–
0001; telephone 206–544–5000, extension 2;
fax 206–766–5683; e-mail
[email protected]; Internet https://
www.myboeingfleet.com.
(3) You may review copies of the service
information at the FAA, Transport Airplane
Directorate, 1601 Lind Avenue, SW., Renton,
Washington. For information on the
availability of this material at the FAA, call
425–227–1221 or 425–227–1152.
(4) You may also review copies of the
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, call 202–741–6030, or go
to: http://www.archives.gov/federal_register/
code_of_federal_regulations/
ibr_locations.html.

Issued in Renton, Washington, on June 16,
2009.
Dorr M. Anderson,
Acting Manager, Transport Airplane
Directorate, Aircraft Certification Service.
[FR Doc. E9–14680 Filed 6–26–09; 8:45 am]
BILLING CODE 4910–13–P

DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 35
[Docket No. RM04–7–006; Order No. 697–
C]

Market-Based Rates For Wholesale
Sales of Electric Energy, Capacity and
Ancillary Services by Public Utilities
Issued June 18, 2009.
AGENCY: Federal Energy Regulatory
Commission.
ACTION: Order on rehearing and
clarification.
SUMMARY: The Federal Energy
Regulatory Commission is granting in
part and denying in part the requests for
rehearing and clarification of its
determinations in Order No. 697–B,
which granted rehearing and
clarification of certain revisions to
Commission regulations and to the
standards for obtaining and retaining
market-based rate authority for sales of
energy, capacity and ancillary services
to ensure that such sales are just and
reasonable.
DATES: Effective Date: This order on
rehearing will become effective July 29,
2009.
FOR FURTHER INFORMATION CONTACT:
Michelle Barnaby (Technical
Information), Office of Energy Market
Regulation, Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502–
8407.
Paige Bullard (Legal Information), Office
of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC
20426, (202) 502–6462.
SUPPLEMENTARY INFORMATION:

Table of Contents

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Paragraph No.
I. Introduction ...................................................................................................................................................................................
II. Background ...................................................................................................................................................................................
III. Discussion ...................................................................................................................................................................................
A. Vertical Market Power .........................................................................................................................................................
Other Barriers to Entry ......................................................................................................................................................
B. Mitigation ..............................................................................................................................................................................

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Federal Register / Vol. 74, No. 123 / Monday, June 29, 2009 / Rules and Regulations

30925
Paragraph No.

Protecting Mitigated Markets .......................................................................................................................................................
C. Implementation Process .......................................................................................................................................................
Clarifications on Implementation Process ........................................................................................................................
IV. Information Collection Statement ..............................................................................................................................................
V. Document Availability ................................................................................................................................................................
VI. Effective Date ..............................................................................................................................................................................
Regulatory Text
Appendix C to Order No. 697–C: Revised Tariff Language
Appendix D–2 to Order No. 697–C: Revised Regional Review Schedule
Before Commissioners: Jon Wellinghoff,
Chairman; Suedeen G. Kelly, Marc Spitzer,
and Philip D. Moeller.

Order on Rehearing and Clarification
I. Introduction
1. In this order, the Commission
addresses requests for rehearing and
clarification of Order No. 697–B.
Specifically, the Commission clarifies
the requirement that sellers file a
notification of change in status when
they acquire sites for new generation
capacity development.1 The
Commission denies the requests for
rehearing of the tariff provision
governing mitigated sales at the metered
boundary and affirms its determination
in Order No. 697–B to revise the
mitigated sales tariff provision in order
to ensure that a mitigated seller making
market-based rate sales at the metered
boundary does not sell power into the
mitigated market either directly or
through its affiliates.2
II. Background
2. On June 21, 2007, the Federal
Energy Regulatory Commission
(Commission) issued Order No. 697,3
codifying and, in certain respects,
revising its standards for obtaining and
retaining market-based rates for public
utilities. In order to accomplish this, as
well as streamline the administration of
the market-based rate program, the
Commission modified its regulations at
18 CFR part 35, subpart H, governing
market-based rate authorization. The
Commission explained that there are
three major aspects of its market-based
regulatory regime: (1) Market power
analyses of sellers and associated
conditions and filing requirements; (2)
1 18

CFR 35.42 (2008).
Rates for Wholesale Sales of
Electric Energy, Capacity and Ancillary Services by
Public Utilities, Order No. 697–B, 73 FR 79,610
(Dec. 30, 2008), FERC Stats. & Regs. ¶ 31,285 (2008).
3 Market-Based Rates for Wholesale Sales of
Electric Energy, Capacity and Ancillary Services by
Public Utilities, Order No. 697, FERC Stats. & Regs.
¶ 31,252 (Order No. 697 or Final Rule), clarified,
121 FERC ¶ 61,260 (2007), order on reh’g, Order No.
697–A, 73 FR 25,832 (May 7, 2008), FERC Stats. &
Regs. ¶ 31,268 (2008); clarified, 124 FERC ¶ 61,055
(2008) (July 17 Clarification Order), order on reh’g,
Order No. 697–B, 73 FR 79,610 (Dec. 30, 2008),
FERC Stats. & Regs. ¶ 31,285 (2008).

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2 Market-Based

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market rules imposed on sellers that
participate in Regional Transmission
Organization (RTO) and Independent
System Operator (ISO) organized
markets; and (3) ongoing oversight and
enforcement activities. Order No. 697
focused on the first of the three features
to ensure that market-based rates
charged by public utilities are just and
reasonable. Order No. 697 became
effective on September 18, 2007.
3. The Commission issued an order
clarifying four aspects of Order No. 697
on December 14, 2007.4 Specifically,
that order addressed: (1) The effective
date for compliance with the
requirements of Order No. 697; (2)
which entities are required to file
updated market power analyses for the
Commission’s regional review; (3) the
data required for horizontal market
power analyses; and (4) what constitute
‘‘seller-specific terms and conditions’’
that sellers may list in their marketbased rate tariffs in addition to the
standard provisions listed in Appendix
C to Order No. 697. The Commission
also extended the deadline for sellers to
file the first set of regional triennial
studies that were directed in Order No.
697 from December 2007 to 30 days
after the date of issuance of the
December 14 Clarification Order.
4. On April 21, 2008, the Commission
issued Order No. 697–A,5 in which it
responded to a number of requests for
rehearing and clarification of Order No.
697. In most respects, the Commission
affirmed the determinations made in
Order No. 697 and denied rehearing of
the issues raised. However, with respect
to several issues, the Commission
granted rehearing or provided
clarification.
5. On July 17, 2008, the Commission
issued an order clarifying certain
aspects of Order No. 697–A related to
the allocation of simultaneous
transmission import capability for
purposes of performing the indicative
4 Market-Based Rates for Wholesale Sales of
Electric Energy, Capacity and Ancillary Services by
Public Utilities, 121 FERC ¶ 61,260 (2007)
(December 14 Clarification Order).
5 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
(2008).

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23
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49
50
53

screens.6 Specifically, that order granted
the requests for rehearing with regard to
footnote 208 of Order No. 697–A and
clarified that in performing the
indicative screen analysis, market-based
rate sellers may allocate the
simultaneous import limit capability on
a pro rata basis (after accounting for the
seller’s firm transmission rights) based
on the relative shares of the seller’s (and
its affiliates’) and competing suppliers’
uncommitted generation capacity in
first-tier markets.7
6. On December 19, 2008, the
Commission issued Order No. 697–B 8
in which it clarified and affirmed the
determinations made in Order No. 697–
A. Specifically, the Commission
provided clarification regarding the
allocation of seasonal and longer
transmission reservations. The
Commission also clarified that it will
require a seller making an affirmative
statement as to whether a contractual
arrangement transfers control to seek a
‘‘letter of concurrence’’ from other
affected parties identifying the degree to
which each party controls a facility, and
to submit these letters with its filing.
The Commission denied the request that
it clarify that only sites for which
necessary permitting for a generation
plant has been completed and/or sites
on which construction for a generation
plant has begun apply under the
definition of ‘‘inputs to electric power
production’’ in § 35.36(a)(4) of the
Commission’s regulations. The
Commission also revised the definition
of ‘‘affiliate’’ in section 35.36(a)(9) of its
regulations to delete the separate
definition for exempt wholesale
generators. In addition, the Commission
provided a number of other
clarifications with regard to, among
others, the pricing of sales of non-power
goods and services and the tariff
provision governing sales at the metered
boundary.
7. On January 28, 2009, in response to
Tampa Electric Company’s (Tampa
Electric) request for extension of time to
comply with the tariff provision on
6 July

17 Clarification Order, 124 FERC ¶ 61,055.
P 5.
8 Order No. 697–B, FERC Stats. & Regs. ¶ 31,285.
7 Id.

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mitigated sales at the metered boundary
as revised in Order No. 697-B, the
Commission issued an order granting
the extension requested by Tampa
Electric until such time as the
Commission issues an order on
rehearing of Order No. 697–B.9 That
order clarified that affected entities
must continue to comply with the
mitigated sales tariff provision adopted
in Order No. 697–A 10 (which became
effective on June 6, 2008), until such
time as the Commission acts on the
requests for rehearing of Order No. 697–
B.
III. Discussion
A. Vertical Market Power
Other Barriers to Entry

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Background
8. Order No. 697 adopted the NOPR
proposal to consider a seller’s ability to
erect other barriers to entry as part of
the vertical market power analysis, but
modified the requirements when
addressing other barriers to entry.11 It
also provided clarification regarding the
information that a seller must provide
with respect to other barriers to entry
(including which inputs to electric
power production the Commission will
consider as other barriers to entry) and
modified the proposed regulatory text in
that regard.12
9. On rehearing, the Commission
clarified that it was not its intent for the
term ‘‘inputs to electric power
production’’ to encompass every
instance of a seller entering into a coal
supply contract with a coal vendor in
the ordinary course of business. The
Commission clarified that Order No. 697
encompasses physical coal sources and
ownership of or control over who may
access transportation of coal via barges
and railcar trains.13 Thus, the
Commission revised its definition of
‘‘inputs to electric power production’’ in
§ 35.36(a)(4) as follows: ‘‘intrastate
natural gas transportation, intrastate
natural gas storage or distribution
facilities; sites for new generation
capacity development; physical coal
supply sources and ownership of or
control over who may access
transportation of coal supplies.’’ 14
9 Market-Based Rates for Wholesale Sales of
Electric Energy, Capacity and Ancillary Services by
Public Utilities, 126 FERC ¶ 61,072 (2009) (Order
Granting Extension of Time to Comply).
10 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at Appendix C.
11 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at
P 440.
12 Id.
13 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at P 176 (emphasis in original).
14 Id.

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10. In Order No. 697–B, the
Commission rejected the Electric Power
Supply Association’s (EPSA) proposal
that the term ‘‘sites for new generation
capacity development’’ mean only sites
with respect to which permits for new
generation have been obtained or where
construction of new generation is
underway, and not encompass land that
could potentially be used for generation.
The Commission explained that ‘‘sites
for new generation capacity
development’’ should be construed to
include ownership of land that could
potentially be used for generation, not
just sites for which permits for new
generation have been obtained or where
construction of new generation is
underway. The Commission also
clarified that ‘‘sites for new generation
capacity development’’ does not include
land that cannot be used for generation
capacity development.15
Requests for Rehearing
11. American Wind Energy
Association (American Wind) requests
rehearing of Order No. 697–B’s
clarification that sites for new
generation capacity development should
be construed to include ownership of
land that could potentially be used for
generation, arguing that the scope and
intent behind this requirement was not
fully illuminated until the
Commission’s clarification of this
requirement in Order No. 697–B.16
American Wind contends that the
Commission should grant rehearing of
the term ‘‘sites for new generation
capacity development’’ so as to only
require reporting for sites for new
generation development that are located
in load pockets where a ‘‘potential’’ for
vertical market power may exist, and
should clarify that it will rely on the
existing rebuttable presumption that all
other sites do not create a barrier to
entry.17
12. American Wind argues that the
Commission’s interpretation of the
reporting burden to include sites that
could potentially be used for generation
substantially increases the regulatory
compliance burden on market-based
rate sellers, and that the increased
burden can be illustrated with respect to
the impact on wind energy developers.
It explains that in developing new wind
power generation sites, wind energy
developers seek to initially lease
approximately 150 acres for each
turbine. American Wind states that in
15 Order No. 697–B, FERC Stats. & Regs. ¶ 31,285
at P 38.
16 American Wind January 21, 2009 Rehearing
Request at 5.
17 Id. at 5–6.

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developing a 100 megawatt project
using 1.5 megawatt wind turbines, a
developer may seek to initially have
10,000 acres of land under control. It
further explains that control over such
land may result from leases that would
likely be made with multiple
landowners over a period of several
months, and that in regions with
significant wind development, it would
not be surprising to find a vast number
of acres for potential new generation
sites under some form of control, via
leases or some other form of agreement,
by wind energy developers.18
13. According to American Wind, the
requirement to file notifications of
change in status every time a marketbased rate seller or its affiliates acquire
sites that potentially could be used for
generation would create a substantial
burden and a competitive risk, while
not providing any associated benefit to
the Commission. American Wind asserts
that wind developers in particular
would be subjected to increased risk of
the disclosure of their proprietary and
competitive information because wind
developers regularly compete for new
land that can be used for wind
development projects.19 It states that in
the development process, wind energy
developers spend significant time and
effort searching for new land that may
be appropriate for wind development
sites, and that information as to where
a wind energy developer is considering
the development of new generation
projects is highly proprietary and
confidential. American Wind contends
that even assuming a filing submitted at
the Commission includes information
‘‘on a summarized, balancing authority
area basis, given the small size of some
balancing authorities, the public release
of such proprietary and confidential
information could lead to competitive
harm.’’ 20 American Wind also argues
that if a seller’s control of potential new
generation sites were alleged to create a
new barrier to entry, the Commission,
either pursuant to a complaint filed by
a third party or a Commission-initiated
investigation, would have ample
authority to take action and challenge
the rebuttable presumption that
ownership or control over sites for new
generation development does not create
a barrier to entry.21
14. American Wind therefore requests
that the Commission grant rehearing of
the term ‘‘sites for new generation
capacity development’’ so as to only
require reporting for sites for new
18 Id.
19 Id.

at 6–7.
at 7.

20 Id.
21 Id.

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generation capacity development that
are located in load pockets where a
‘‘potential’’ for vertical market power
may exist. American Wind argues that
for the purposes of this reporting
requirement, the Commission could
define load pockets as submarkets
where the Commission has determined
that internal transmission constraints
make the market smaller than the
balancing authority area, RTO/ISO
footprint or RTO/ISO submarket.22
15. If the Commission declines to
grant its request to only require
reporting for sites for new generation
development that are located in load
pockets where a ‘‘potential’’ for vertical
market power may exist, American
Wind requests clarification that the
Commission will only require reporting
for sites for new generation capacity
development when ‘‘site control’’ is first
required to be demonstrated in the
interconnection process.23 American
Wind claims that sites that have not yet
been required to demonstrate site
control in the interconnection process
would not likely be used to enhance a
seller’s vertical market power, and
accordingly, there is no need for the
Commission to be notified of such sites
prior to when ‘‘site control’’ is required
to be demonstrated. American Wind
argues that using this milestone as the
triggering point for when a seller must
notify the Commission of sites for new
generation capacity development
‘‘would better align the reporting
requirement with the underlying
vertical market power concerns that are
at the heart of the requirement’’ and
‘‘would strike a better balance between
the Commission’s regulatory concerns
and the compliance burden on and
competitive risks to market-based rate
sellers.’’ 24
Commission Determination
16. We will deny American Wind’s
request for rehearing of the definition of
‘‘inputs to electric power production’’
so that it requires only reporting for
sites for new generation capacity
development that are located in load
pockets where a ‘‘potential’’ for vertical
market power may exist. Such a revision
to the requirement is too narrowly
focused and therefore would not allow
the Commission to timely monitor for
potential barriers to entry or affiliate
abuse involving generation sites. Since
load pockets typically exist in areas
(e.g., population centers) that are not
well-suited for the development of
renewable generation sources (e.g., large
22 Id.
23 Id.

at 9.
at 11.

24 Id.

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wind farms requiring thousands of acres
of land),25 limiting the reporting of sites
for new generation development to just
load pockets would mean that the
Commission would not be informed of
most instances where land was being
acquired for the development of new
renewable generation capacity.
17. With respect to American Wind’s
alternative request that the Commission
only require reporting for sites for new
generation capacity development when
site control is first required to be
demonstrated in the interconnection
process, we believe this approach has
merit, as modified below. Modifications
are necessary because it is not clear that
American Wind’s request would address
both its concerns about the disclosure of
commercially sensitive information and
the Commission’s regulatory concerns
regarding a seller’s ability to erect
barriers to entry through its acquisition
of sites for new generation capacity
development. First, the information
provided in an interconnection request,
including the demonstration of site
control, is not required to be public.26
Second, transmission providers post the
location of interconnection requests on
OASIS by county and State, but do not
post the identity of the interconnection
customer when the interconnection
request is made ‘‘because disclosing the
identity at that early stage may put the
Interconnection Customer at a
competitive disadvantage and its project
at risk.’’ 27 Thus, the American Wind
alternative approach would require the
seller to report information that in the
interconnection process may be
considered non-public and proprietary.
While American Wind’s concerns about
the disclosure of commercially sensitive
information could be addressed by
allowing sellers to file site information
with the Commission confidentially, we
do not believe that it is appropriate to
routinely permit change in status
reports to be filed at the Commission as
non-public documents. One of the
purposes of the change of status
reporting requirement is to provide
interested parties the opportunity to
intervene and comment if they believe
25 See id. at 6 (stating that ‘‘in developing a 100
MW project using 1.5 MW wind turbines
(approximately 65 turbines), a developer may seek
to initially have under control 10,000 acres of
land.’’).
26 Standardization of Generator Interconnection
Agreements and Procedures, Order No. 2003, FERC
Stats. & Regs. ¶ 31,146, at P 270 (2003), order on
reh’g, Order No. 2003–A, FERC Stats. & Regs.
¶ 31,160, order on reh’g, Order No. 2003–B, FERC
Stats. & Regs. ¶ 31,171 (2004), order on reh’g, Order
No. 2003–C, FERC Stats. & Regs. ¶ 31,190 (2005),
aff’d sub nom. Nat’l Ass’n of Regulatory Util.
Comm’rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007).
27 Id. P 114.

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30927

the seller’s acquisition of sites for new
generation capacity development creates
a barrier to entry, which could be
undermined if such reports were
routinely filed with confidential
information redacted.28
18. Accordingly, in order to address
our regulatory concerns and the
concerns of American Wind, we grant
rehearing and revise section 35.42 of our
regulations to require, for all entities
with market-based rate authorization,
quarterly reporting of a seller’s
acquisition of a site or sites for new
generation capacity development for
which site control has been
demonstrated in the interconnection
process and for which the potential
number of megawatts that are
reasonably commercially feasible on the
site or sites for new generation capacity
development is equal to 100 megawatts
or more. For the purposes of this
reporting requirement, we will use the
definition of ‘‘site control’’ that is
provided in section 1 of the Standard
Large Generator Interconnection
Procedures (LGIP).29 To the extent that
a seller elects to make a monetary
deposit so that it may demonstrate site
control at a later time in the
interconnection process,30 such deposit
will trigger this quarterly reporting
requirement instead of the
demonstration of site control if the
28 See Order No. 697, FERC Stats. & Regs.
¶ 31,252 at P 446; 1018 (explaining that the
Commission will allow intervenors to rebut the
presumption that a seller’s ownership of, control of
or affiliation with entities that own or control
inputs to electric power production do not allow a
seller to raise entry barriers).
29 Section 1 of the LGIP adopted in Order No.
2003 defines ‘‘site control’’ as ‘‘documentation
reasonably demonstrating: (1) Ownership of, a
leasehold interest in, or a right to develop a site for
the purpose of constructing the Generating Facility;
(2) an option to purchase or acquire a leasehold site
for such purpose; or (3) an exclusivity or other
business relationship between Interconnection
Customer and the entity having the right to sell,
lease or grant Interconnection Customer the right to
possess or occupy a site for such purpose.’’ Order
No. 2003, FERC Stats. & Regs. ¶ 31,146, LGIP § 1.
The same requirements apply to small generators
and wind generating facilities. See Order No. 2006,
FERC Stats. & Regs. ¶ 31,180, Small Generator
Interconnection Procedures § 1.5; Interconnection
for Wind Energy, Order No. 661, FERC Stats. & Regs.
¶ 31,186, order on reh’g, Order No. 661–A, FERC
Stats. & Regs. ¶ 31,198 (2005).
30 See LGIP § 3.3.1 (stating that ‘‘[t]o initiate an
Interconnection Request, Interconnection Customer
must submit all of the following: (i) a $10,000
deposit, (ii) a completed application in the form of
Appendix 1, and (iii) demonstration of Site Control
or a posting of an additional deposit of $10,000.
Such deposits shall be applied toward any
Interconnection Studies pursuant to the
Interconnection Request. If Interconnection
Customer demonstrates Site Control within the cure
period specified in Section 3.3.3 after submitting its
Interconnection Request, the additional deposit
shall be refundable; otherwise, all such deposit(s),
additional and initial, become non-refundable.’’).

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potential number of megawatts that are
reasonably commercially feasible on the
site or sites for new generation capacity
development is equal to 100 megawatts
or more.31 All market-based rate sellers
will be required to report the acquisition
of control of sites for new generation
capacity development on a quarterly
basis instead of within 30 days of the
acquisition.32 Such quarterly filings
must be submitted within 30 days after
the end of each quarter, e.g., by April 30
for the first quarter. Thus, the time
period in which sellers are required to
report the acquisition of control of sites
for new generation capacity
development is being extended, which
will ease some of the administrative
burden about which American Wind
has raised concerns. For all changes in
status other than the acquisition of
control of sites for new generation
capacity development, all sellers will
still be required to file a change in status
report no later than 30 days after the
change in status occurs.33
19. The quarterly reports that entities
will be submitting to report the
acquisition of control of a site or sites
for new generation capacity
development must include: (a) The
number of sites acquired; (b) the
relevant geographic market in which the
sites are located; 34 and (c) the
maximum potential number of
megawatts that are reasonably
commercially feasible on the sites
31 We note that if a term other than ‘‘site control’’
is used to describe the specific means by which site
control is demonstrated in the interconnection
process, then the reporting requirement will be
triggered when a demonstration of site control is
made under that term. For example, ‘‘site
exclusivity’’ is considered as the specific means by
which site control is determined in the California
Independent System Operator’s (CAISO’s)
Generator Interconnection Process Reform tariff
amendment. See California Independent System
Operator Corp., 124 FERC ¶ 61,292, at P 40–41, 63
(2008). Therefore, the demonstration of ‘‘site
exclusivity’’ in the interconnection process set forth
in the CAISO’s Generator Interconnection Process
Reform tariff amendment will trigger the quarterly
requirement to report a seller’s acquisition of
control of a site or sites for new generation capacity
development.
32 In this context, ‘‘control’’ refers to ‘‘site
control’’ as it is defined in the LGIP, or as explained
in footnote 31.
33 A change in status includes, but is not limited
to, the following: Ownership or control of
generation capacity that results in net increases of
100 MW or more, or of inputs to electric power
production, or ownership, operation or control of
transmission facilities, or affiliation with any entity
not disclosed in the application for market-based
rate authority that owns or controls generation
facilities or inputs to electric power production or
that owns, operates or controls transmission
facilities, or affiliation with any entity that has a
franchised service area. See 18 CFR 35.42.
34 The relevant geographic markets include those
defined in Order No. 697 and those defined in
subsequent Commission orders. Order No. 697,
FERC Stats. & Regs. ¶ 31,252 at P 231–32, 237.

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reported, which must be justified.35 The
information regarding the maximum
potential number of megawatts for the
sites may be reported on an aggregate
basis for each relevant geographic
market(s) in which the site(s) are
located, i.e., without providing the
specific location of particular sites.
Sellers must provide a justification for
the number of megawatts that they
estimate could be developed on the site
or sites. Such justification must be
based on the maximum potential
number of megawatts that could be
produced on the site with the
technology for which the site was
acquired. Sellers must be forthright in
estimating and reporting the maximum
potential number of megawatts that are
reasonably commercially feasible on the
site or sites for new generation capacity
development. The Commission will use
all of this reported information to
identify sellers that may be erecting
barriers to entry. We will revise section
35.42 of our regulations to reflect this
site acquisition change to the change in
status reporting requirement.
20. Separate and apart from the above
reporting requirement, and in order to
address our concern that Sellers may
acquire land that is not used for the
development of new generation
capacity, and that is instead acquired for
the purpose of preventing new
generation capacity from being
developed on that land, a Seller must
also report any land it has acquired,
taken a leasehold interest in, obtained
an option to purchase or lease, or
entered into an exclusivity or other
arrangement to acquire for the purpose
of developing a generation site and for
which site control has not yet been
demonstrated (as discussed above)
during the prior three years (triggering
event), and for which the potential
number of megawatts that are
reasonably commercially feasible on the
land for new generation capacity
development is equal to 100 megawatts
or more. A Seller must report each such
triggering event in a single report by
January 1 of the year following the
calendar year in which the triggering
event occurred. Thus, for example, if a
Seller acquires land for new generation
capacity development in January 2009,
and additional land in March 2009 and
it has not demonstrated site control for
generation projects on that land (as
described above) as of January and
35 We note that if a site is later expanded to allow
for additional generation capacity development and
such expansion results in an increase of 100
megawatts or more, a seller will be required to file
a notification of change in status to notify the
Commission of such a change within 30 days after
the end of that quarter.

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March 2012, respectively, then such
Seller must file a change in status report
notifying the Commission of both
acquisitions by January 1, 2013. The
information that must be provided and
the aggregation of the maximum
potential number of megawatts by
relevant geographic market is the same
as required in the quarterly reports, as
described above. We will revise section
35.42 of our regulations to reflect this
additional change to the change in
status reporting requirement.
21. Finally, for acquired, leased or
optioned land lacking site control that
have already been held for three years
or more prior to the effective date of this
order, a Seller must report the required
information by January 1, 2010, unless
this information has been previously
provided to the Commission.
22. We believe that our revision to
this requirement strikes a balance by
addressing American Wind’s concern
regarding the burden of the existing
requirement and its concern that
commercially sensitive information
about sites for wind generation
development will be made public, and
by also providing the Commission with
the information necessary to evaluate a
seller’s ability to erect barriers to entry.
In particular, permitting the information
on sites for new generation capacity
development to be provided on an
aggregate basis for each relevant
geographic market reduces any potential
competitive harm that could result from
reporting the location of the sites (since
reporting will be on an aggregate basis),
and also enables the Commission,
which evaluates vertical market power
by examining the relevant geographic
market in which a seller is located, to
obtain the information it needs to
evaluate a seller’s ability to exercise
market power in a particular relevant
geographic market. Requiring quarterly
(and yearly, as necessary) reporting of
sites acquired for new generation
capacity development also reduces the
administrative burden on sellers, which
previously were required to report the
acquisition of sites within 30 days of the
acquisition. In addition, requiring
reporting on a quarterly basis (and
yearly, as necessary) will likely reduce
any potential competitive harm that
could result from the disclosure of the
nominal information regarding the
location of the site or sites for new
generation capacity development.
Further, in their applications for marketbased rate authority and their updated
market power analyses, sellers are
obligated to make an affirmative
statement that they have not erected
barriers to entry into the relevant market
and will not erect barriers to entry into

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the relevant market. This continuing
obligation provides assurance to the
Commission that a seller is not erecting
barriers to entry.36
B. Mitigation
Protecting Mitigated Markets
Sales at the Metered Boundary

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Background
23. In Order No. 697, the Commission
stated that it would continue to apply
mitigation to all sales in the balancing
authority area in which a seller is found,
or presumed, to have market power.
However, the Commission said it would
allow mitigated sellers to make marketbased rate sales at the metered boundary
between a balancing authority area in
which a seller is found, or presumed, to
have market power and a balancing
authority area in which the seller has
market-based rate authority, under
certain circumstances.37 The
Commission also adopted a requirement
that mitigated sellers wishing to make
market-based rate sales at the metered
boundary between a balancing authority
area in which the seller was found, or
presumed, to have market power and a
balancing authority area in which the
seller has market-based rate authority
maintain sufficient documentation and
use a specific tariff provision for such
sales.38
24. On rehearing in Order No. 697–A,
the Commission revised the tariff
language governing market-based rate
sales at the metered boundary to
conform with the discussion in the
December 14 Clarification Order
regarding use of the term ‘‘mitigated
market.’’ The Commission stated that, as
explained in the December 14
Clarification Order, ‘‘balancing
authority area in which a seller is found,
or presumed, to have market power’’ is
a more accurate way to describe the area
in which a seller is mitigated.39
25. In addition, after considering
comments regarding the difficulty of
determining and documenting intent,
the Commission decided in Order No.
697–A to eliminate the intent element of
the tariff provision, which stated that
‘‘any power sold hereunder is not
intended to serve load in the seller’s
mitigated market.’’ Because the
Commission eliminated the seller’s
36 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at
P 447.
37 Id. P 817 (citing North American Electric
Reliability Corporation, Glossary of Terms Used in
Reliability Standards at 2 (2007), available at
ftp://www.nerc.com/pub/sys/all_updl/standards/rs/
Glossary_02May07.pdf)).
38 Id. P 830.
39 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at P 333.

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intent requirement, it modified the tariff
provision to require that ‘‘the mitigated
seller and its affiliates do not sell the
same power back into the balancing
authority area where the seller is
mitigated.’’ 40 In this regard, the
Commission noted that ‘‘[t]o provide
additional regulatory certainty for
mitigated sellers, the Commission
clarified that once the power has been
sold at the metered boundary at marketbased rates, the mitigated seller and its
affiliates may not sell that same power
back into the mitigated balancing
authority area, whether at cost-based or
market-based rates.’’ 41 The Commission
also stated that because it was
eliminating the intent requirement, it
need not address issues raised regarding
documentation necessary to
demonstrate the mitigated seller’s
intent.
26. Further, in response to a request
for clarification submitted by the
Pinnacle West Companies (Pinnacle),
the Commission also clarified in Order
No. 697–A that mitigated sellers and
their affiliates are prohibited from
selling power at market-based rates in
the balancing authority area in which a
seller is found, or presumed, to have
market power.42 Accordingly, the
Commission clarified that an affiliate of
a mitigated seller is prohibited from
selling power that was purchased at a
market-based rate at the metered
boundary back into the balancing
authority area in which the seller has
been found, or presumed, to have
market power. The Commission stated
that to the extent that the mitigated
seller or its affiliates believe that it is
not practical to track such power, they
can either choose to make no marketbased rate sales at the metered boundary
or limit such sales to sales to end users
of the power, thereby eliminating the
danger that they will violate their tariff
by re-selling the power back into a
balancing authority in which they are
mitigated.43
27. In Order No. 697–B, in response
to the rehearing request of E.ON U.S.
LLC (E.ON), the Commission explained
that it appreciated concerns regarding
the difficulty of defining the term ‘‘same
power.’’ For this reason, the
Commission revised the tariff provision
for market-based rate sales at the
metered boundary, which included
revising the provision stating that the
‘‘Seller and its affiliates do not sell the
same power back into the balancing
authority area where the seller is
40 Id.

P 334.
n.464.
42 Id. P 335.
43 Id. P 336.
41 Id.

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30929

mitigated,’’ to state that ‘‘if the Seller
wants to sell at the metered boundary of
a mitigated balancing authority area at
market-based rates, then neither it nor
its affiliates can sell into that mitigated
balancing authority area from the
outside.’’ The Commission noted that
this revised tariff language will prevent
a mitigated seller making market-based
rate sales at the metered boundary from
selling power into the mitigated market
through its affiliates. It also explained
that sellers may choose to make no
market-based rate sales at the metered
boundary, or to limit such sales to end
users of the power, thereby eliminating
the danger they will violate their tariff
by re-selling power back into a
balancing authority in which they are
mitigated.44
Requests for Rehearing
28. On rehearing of Order No. 697–B,
E.ON again takes issue with the
mitigated sales tariff provision, arguing
that the Commission erred in revising
the mitigated sales tariff provision in
Order No. 697–B. E.ON contends that
the revised tariff provision is overbroad
and prohibits legitimate transactions. It
argues that the tariff provision should be
revised to state that ‘‘(ii) if the Seller
sells at the metered boundary of a
mitigated balancing authority area at
market-based rates, then neither it nor
its affiliates can sell into that mitigated
balancing authority area from the
outside at the same border for delivery
at the same time except pursuant to
long-term (one-year or longer)
agreements or as a result of changed
circumstances.’’ 45 E.ON argues that, as
revised in Order No. 697–B, the tariff
provision governing mitigated sales
does not expressly state that a border
sale need actually occur. E.ON suggests
that the Commission should change the
words ‘‘wants to sell’’ to ‘‘sells’’ to
eliminate any risk of misinterpretation.
In support of its proposal, E.ON argues
that the mitigated sales tariff provision
should contain a ‘‘temporal limitation’’
so that it cannot be read to prohibit a
mitigated seller or its affiliates from ever
selling from the outside into the
mitigated balancing authority area.
E.ON believes that the Commission
intended only to stop the ‘‘looping’’ of
power in a manner that circumvents the
mitigation imposed on an entity.46
29. E.ON also argues that the
mitigated sales tariff provision should
contain an exemption for retail or
44 Order No. 697–B, FERC Stats. & Regs. ¶ 31,285
at P 77 (citing Order No. 697–A, FERC Stats. & Regs.
¶ 31,268 at P 336).
45 E.ON January 21, 2009 Rehearing Request at 3,
5.
46 Id. at 8.

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wholesale cost-based requirements
contracts into the mitigated balancing
authority area from the outside so that
long-term purchases from outside a
mitigated market used to serve retail or
cost-based wholesale requirements
customers do not restrict the ability of
a mitigated seller from making a spot
‘‘outbound’’ border sale. According to
E.ON, failure to modify the condition in
this manner would severely restrict the
ability of its public utility subsidiaries
Louisville Gas and Electric Company
and Kentucky Utilities Company to
make truly ‘‘outbound’’ off-system sales
at the border of their control area,
leading to higher prices.47 E.ON also
proposes adding language to the
condition so as to carve out long-term
agreements of one-year or more in
duration that provide for the sale of
power into the mitigated market from
the outside. E.ON contends that as
revised in Order No. 697–B, the
mitigated sales tariff provision could
prohibit transactions necessitated by
reserve sharing agreements or changed
operational circumstances, and could
have a chilling effect on forward
contracting by forcing mitigated sellers
to only transact in real time because of
their concerns that they may guess
wrong and need to buy power at the last
minute if they are short, or sell power
at the last minute if called upon under
a reserve sharing agreement.48 In
addition, E.ON asserts that the revised
mitigated sales tariff provision could
prohibit opportunity purchases by
utilities that seek to reduce the costs of
serving load.49
30. Pinnacle, too, seeks further
revision to the mitigated sales tariff
provision and argues that the
Commission erred in linking all marketbased rate sales made at the metered
boundary to all incoming sales into a
mitigated balancing authority area.
Pinnacle requests that the Commission
clarify that making a border sale does
not prohibit all future sales of a
mitigated seller or its affiliates from
entering the mitigated balancing
authority area. It states that, at a
minimum, the Commission should
clarify that it does not intend for the
revised provision to capture cost-based
sales into or out of a mitigated balancing
authority area.50 Pinnacle states that if
the revised provision is interpreted to
prohibit any subsequent sales of a
mitigated seller or its affiliates from
entering the mitigated balancing

authority area, this would completely
preclude the mitigated seller from
selling into the mitigated balancing
authority area. Such a result, Pinnacle
contends, could endanger the stability
of the Phoenix Valley Load Pocket in
the event of an emergency,51 and could
result in Pinnacle violating its mustoffer requirements. Specifically,
Pinnacle states that if it is not permitted
to make sales into the mitigated
balancing authority area, or is
effectively prohibited from making sales
at border points, its posting of available
capacity will be less effective for the
Southwest in that Pinnacle would have
to withhold available generation due to
its inability to make sales in certain
areas.52
31. MidAmerican Energy Company
(MidAmerican) and American Electric
Power Service Corporation (AEP) also
seek rehearing of the mitigated sales
tariff provision as revised in Order No.
697–B. These petitioners argue that the
Commission erred in adopting an overly
broad mitigation provision that could
restrict legitimate transactions. They
contend that under the tariff provision
adopted in Order No. 697–B, mitigated
utilities are presented with three
alternatives, each of which
‘‘unnecessarily and unfairly’’
disadvantages their customers: (i)
Decline to make market-based rate sales
and thereby forego revenues used to
reduce system costs; (ii) decline to
import power from ‘‘the outside’’ and
thereby forego least-cost resources that
could be used to reliably serve load and
make sales within the mitigated market;
or (iii) make sales to customers within
the mitigated market at prices that may
not recover incremental costs, thereby
unfairly subsidizing those
transactions.53 MidAmerican and AEP
therefore assert that the Commission
should rescind Order No. 697–B’s
revision and revert to the mitigated sales
tariff provision adopted in Order No.
697. According to these petitioners, the
tariff provision adopted in Order No.
697 captures transactions purposefully
structured to evade mitigation while
permitting utilities to continue to
engage in legitimate transactions from
the ‘‘outside,’’ even when energy
scheduled under those transactions
subsequently is reflected in the price for
opportunity sales made within the
balancing authority area.54
32. MidAmerican and AEP argue that
if the Commission declines to grant

rehearing, it should clarify that the
mitigated sales tariff provision applies
only to short-term purchases made from
the ‘‘outside’’ by the mitigated seller
and not to deliveries scheduled from the
mitigated seller’s own generation
originating ‘‘outside’’ the mitigated
balancing authority area or from longterm capacity contracts entered into to
meet load requirements. These
petitioners contend that these
arrangements ‘‘do not involve the
Commission’s ricochet concern and
should not be swept within the Order
No. 697–B mitigation provision.’’ 55
33. Xcel Energy Services Inc. (Xcel)
requests clarification that the
prohibition on sales into the mitigated
balancing authority area does not
prevent a mitigated seller from engaging
in a purchase of economy power from
outside the mitigated balancing
authority area in order to lower costs for
serving native load. It argues that
mitigated sellers that make sales of
power at border locations may have
opportunities to enter into legitimate
economy purchases outside the
balancing authority area that would
serve to lower overall generation costs
to their native load customers. Xcel
contends that one mitigation option is to
‘‘track the power from a border sale with
the possibility of retroactive repricing.’’ 56
34. Xcel requests clarification that
mitigated sellers are only prohibited
from making sales into a mitigated
balancing authority area if the seller is
simultaneously engaged in a sale at the
metered boundary.57 In support of this
request, Xcel argues that during periods
when the seller is not making sales at
the border of its mitigated balancing
authority area, there would be no way
for the seller or its affiliates to benefit
from their market power in the
mitigated balancing authority area
through a sale that originates outside of
that mitigated balancing authority
area.58 Xcel therefore asks for
clarification that it is permitted to enter
into a sale at a delivery point located
outside of the mitigated balancing
authority area to a counterparty within
the balancing authority area.
35. The Edison Electric Institute (EEI)
likewise seeks rehearing of the mitigated
sales tariff provision as set forth in
Order No. 697–B.59 EEI contends that
55 Id.

at 8.
January 21, 2009 Request for Clarification

56 Xcel

at 7.
57 Id.

47 Id.

at 10.
48 Id. at 12.
49 Id. at 13.
50 Pinnacle January 21, 2009 Rehearing Request at
5.

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51 Id.

at 3–4.
52 Id. at 4.
53 MidAmerican January 21, 2009 Rehearing
Request at 6.
54 Id. at 7–8.

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at 5.
at 8.
59 We note that EEI’s request for rehearing of the
mitigated sales tariff provision is out-of-time insofar
as EEI did not raise issues concerning mitigated
sales at the metered boundary on rehearing of Order
58 Id.

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the revised provision will unnecessarily
constrain sales by mitigated sellers and
their affiliates to the detriment of
customers in all markets. EEI argues that
as revised in Order No. 697–B, the
mitigated sales tariff provision could be
interpreted to prohibit all sales by
mitigated sellers and their affiliates into
a mitigated market from the outside if
the sellers opt to engage in one or more
metered boundary sales. EEI asserts that
this interpretation would completely
exclude all sales into the mitigated
balancing authority area by a mitigated
seller and its affiliates, removing these
sellers from the marketplace and
exacerbating any potential imbalance of
market power in the mitigated balancing
authority area.60 EEI contends that the
revised tariff language could be
interpreted to violate certain must-offer
and load-following requirements.
36. EEI argues that the Commission
should return to the intent-based
concept adopted in Order No. 697,
while also identifying five types of
transactions that would be permitted
without first needing to demonstrate
intent even if a mitigated seller does
engage in market-based rate sales at the
metered boundary.61 EEI asserts that the
following five types of transactions
should be permitted without first
needing to demonstrate intent, even if a
mitigated seller does engage in marketbased rate border sales: (1) Sales at
‘‘liquid trading hubs’’ or into ISO and
RTO markets outside of the seller’s
mitigated market; (2) cost-based sales in
which title transfers within the
mitigated market (whether they are
sourced and sunk in the mitigated
market, are sourced ‘‘into’’ the mitigated
market from the outside by the seller or
its affiliates, or are wheeled ‘‘out of’’ the
mitigated market by a purchaser); (3)
sales to load-serving entities such as
investor-owned utilities, municipalities,
and cooperatives that serve retail load
outside the mitigated market, even if
those entities may at times need to sell
power back into the mitigated market if
their supply is too great (since the
timing and occurrence of such excesspower sales back into the mitigated
market will be beyond the control of the
mitigated seller); (4) other types of
transactions that are independent of the
border sales, such as sales of blocks of
power to be delivered at dates and times
other than the border sale block of
power, power made available under
Nos. 697 and 697–A and appears to be an attempt
to re-litigate the determinations made by the
Commission in those orders.
60 EEI January 22, 2009 Corrected Rehearing
Request at 5–6.
61 Id. at 3.

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must-offer requirements, and loadfollowing power; and (5) to bolster
reliability, the Commission should
clarify that the border sale constraints
do not require a mitigated seller or its
affiliates, which otherwise would be
precluded from selling power into the
mitigated area from the outside, to
withhold making those sales during
times at which the seller or affiliates are
called on to act to maintain system
reliability. EEI argues that at a
minimum, the Commission should
clarify that the border sales constraints
will not prevent emergency sales, sales
that are required to maintain reserve
levels or to comply with system
redispatch obligations, or sales that are
otherwise authorized by the
Commission either generically or caseby-case.62
37. EEI also includes an expedited
motion for partial stay in its rehearing
request in which it asks that the
Commission stay the effectiveness of the
border sales constraints set forth in
Order Nos. 697, 697–A and 697–B until
at least 30 days after the Commission
has acted on the merits of EEI’s request
for rehearing.63
38. Separately, Tampa Electric
submitted a motion for an extension of
time to comply with the revised
mitigated sales tariff provision set forth
in Order No. 697–B. Tampa Electric
requests that the Commission defer the
effective date of the modified language
governing mitigated sales at the metered
boundary pending Commission action
on requests for rehearing of Order No.
697–B on this issue.64 Tampa Electric
also states that it supports EEI’s request
for rehearing.
39. On January 27, 2009, the National
Rural Electric Cooperative Association
(NRECA) and the American Public
Power Association (APPA) filed an
answer in response to EEI’s motion for
partial stay. NRECA and APPA argue
that EEI’s motion for partial stay should
be denied because EEI does not
demonstrate that a stay is appropriate.
They argue that EEI does not specify any
irreparable injury that EEI or its member
companies will suffer absent a stay,
does not address whether the requested
62 Id.

at 8–9.
at 9.
64 In its request for an extension of time to comply
with the revised mitigated sales tariff provision,
Tampa Electric states that it supports EEI’s request
for rehearing. On January 28, 2009, the Commission
issued an order granting Tampa Electric’s request
for an extension of time to comply with the tariff
provision on mitigated sales at the metered
boundary as revised in Order No. 697–B until such
time as the Commission issues an order on
rehearing of Order No. 697–B. Order Granting
Extension of Time to Comply, 126 FERC ¶ 61,072;
see supra P 6.
63 Id.

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stay would substantially harm other
parties, and does not show that the stay
is in the public interest. They point out
that EEI’s request for rehearing is the
third time in this proceeding that sellers
have requested the Commission to
modify the restrictions on market-based
sale at the metered boundaries of
mitigated balancing authority areas.65
NRECA and APPA also argue that
ending all restrictions on market based
rate sales at the metered boundary of
balancing authority areas in which a
seller is mitigated, even temporarily,
would harm wholesale markets and
customers.66
Commission Determination
Procedural Issues
40. We find that EEI does not provide
the required justification for a stay of
the mitigated sales tariff provision.
Under section 705 of the Administrative
Procedure Act (APA), the Commission
may stay its action when it finds that
‘‘justice so requires.’’ 67 In addressing
motions for stay, the Commission
considers: (1) Whether the moving party
will suffer irreparable injury without a
stay; (2) whether issuing a stay will
substantially harm other parties; and (3)
whether a stay is in the public
interest.68 The Commission’s general
policy is to refrain from granting a stay
of its orders, to assure definiteness and
finality in Commission proceedings.69
The key element in the inquiry is
irreparable injury to the moving party.70
If a party is unable to demonstrate that
it will suffer irreparable harm absent a
stay, we need not examine the other
factors.71 However, the Commission
may examine the other factors where
appropriate.72
41. EEI’s request for stay does not
address whether it will suffer
irreparable injury without a stay of the
mitigated sales tariff provision, and also
does not address whether issuing a stay
65 NRECA

and APPA January 27, 2009 Answer at

1–2.
66 Id.

at 3–4.
U.S.C. 705 (2006).
68 Pinnacle West Capital Corp., 115 FERC
¶ 61,064, at P 8 (2006) (citing CMS Midland, Inc.,
Midland Cogeneration Venture Limited Partnership,
56 FERC ¶ 61,177, at 61,361 (1991), aff’d sub nom.
Michigan Municipal Cooperative Group v. FERC,
990 F.2d 1377 (D.C. Cir. 1993), cert. denied, 510
U.S. 990 (1993)).
69 Id.
70 Id.
71 CMS Midland, Inc., Midland Cogeneration
Venture Limited Partnership, Midland Cogeneration
Venture Limited Partnership, 56 FERC ¶ 61,177, at
61,631 (1991) (footnote omitted).
72 Pinnacle West Capital Corp., 115 FERC
¶ 61,064, at P 8 (2006) (citing The Montana Power
Company, Confederated Salish and Kootenai Tribes
of the Flathead Reservation, 85 FERC ¶ 61,400, at
62,535 (1998)).
67 5

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Federal Register / Vol. 74, No. 123 / Monday, June 29, 2009 / Rules and Regulations

will substantially harm other parties or
whether a stay is in the public interest.
Rather, EEI’s request for stay consists
only of the following statement: ‘‘[g]iven
the serious, negative potential effects of
the border sales related constraints set
out in Orders No. 697, 697–A, and 697–
B on market participants and customers
in mitigated and non-mitigated markets,
EEI requests that the Commission stay
the effectiveness of those constraints
until at least 30 days after the
Commission has acted on the merits of
EEI’s request for rehearing.’’ 73 This
claim is too broad and speculative to
justify the granting of injunctive relief.74
We also note that EEI did not raise
issues concerning mitigated sales at the
metered boundary on rehearing of Order
Nos. 697 and 697–A. Because EEI fails
to provide the required justification for
a stay of the mitigated sales tariff
provision, EEI’s motion for a partial stay
is denied.75
Substantive Issues
42. We deny the requests for rehearing
concerning the mitigated sales tariff
provision. However, we agree with
E.ON that the tariff provision should be
revised to state ‘‘if the Seller sells’’
instead of ‘‘if the Seller wants to sell
* * *.’’ We clarify that it is not the
seller’s intent, but rather the seller’s
action that triggers the limitation set
forth in the mitigated sales tariff
provision. We affirm our determination
to revise the mitigated sales tariff
provision in Order No. 697–B in order
to ensure that a mitigated seller making
market-based rate sales at the metered
boundary does not sell power into the
mitigated market either directly or
through its affiliates. Thus, we will
revise the mitigated sales tariff
provision to provide that ‘‘if the Seller
73 EEI

January 21, 2009 Rehearing Request at 9.
Wisconsin Gas v. FERC, 758 F.2d 669, 674
(D.C. Cir. 1985) the court stated that, to meet the
irreparable injury test for granting a stay:
‘‘First, the injury must be both certain and great;
it must be actual and not theoretical. Injunctive
relief ‘‘will not be granted against something merely
feared as liable to occur at some indefinite time,’’
Connecticut v. Massachusetts, 282 U.S. 660, 674, 75
L. Ed. 602, 51 S. Ct. 286 (1931); the party seeking
injunctive relief must show that ‘‘the injury
complained of [is] of such imminence that there is
a ‘clear and present’ need for equitable relief to
prevent irreparable harm.’’ Ashland Oil, Inc. v. FTC,
409 F. Supp. 297, 307 (D.D.C.), aff’d, 179 U.S. App.
D.C. 22, 548 F.2d 977 (D.C. Cir. 1976) (citations and
internal quotations omitted).’’
75 In granting Tampa Electric’s request for
extension of time to comply with the tariff
provision on mitigated sales at the metered
boundary as revised in Order No. 697–B, the
Commission clarified that affected entities must
continue to comply with the mitigated sales tariff
provision adopted in Order No. 697–A until such
time as the Commission acts on the requests for
rehearing of Order No. 697–B. Order Granting
Extension of Time to Comply, 126 FERC ¶ 61,072.

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74 In

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sells at the metered boundary of a
mitigated balancing authority area at
market-based rates, then neither it nor
its affiliates can sell into that mitigated
balancing authority area from the
outside.’’ 76 Petitioners’ arguments on
rehearing of Order No. 697–A indicated
that they cannot guarantee that sales at
the metered boundary ultimately serve
load in a competitive market beyond the
balancing authority area where the
seller is mitigated.77 As explained in
Order No. 697, ‘‘[a]llowing market-based
rate sales by a seller that has been found
to have market power, or has so
conceded, in the very market in which
market power is a concern is
inconsistent with the Commission’s
responsibility under the FPA to ensure
that rates are just and reasonable and
not unduly discriminatory.’’ 78
Accordingly, mitigated sellers and their
affiliates are prohibited from selling
power at market-based rates in the
balancing authority area in which the
seller is found, or presumed, to have
market power.79 Thus, we affirm the
Commission’s determination to revise
the mitigated sales tariff provision in
Order No. 697–B in order to ensure that
a mitigated seller making market-based
rate sales at the metered boundary does
not sell power into the mitigated market
either directly or through its affiliates.
We also reiterate that mitigated sellers
may choose to make no market-based
rates sales at the metered boundary, or
to limit such sales to end users, thereby
eliminating the risk that they will re-sell
power back to the balancing authority
area where they are mitigated.80
43. With respect to petitioners’
arguments that the mitigated sales tariff
76 Order No. 697–B, FERC Stats. & Regs. ¶ 31,285
at Appendix C.
77 Id. P 66–67, 69; E.ON May 21, 2008 Rehearing
Request at 12–14, Pinnacle May 21, 2008 Rehearing
Request at 4–6.
78 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at
P 819. The Commission also stated ‘‘While we
generally agree that it is desirable to allow marketbased rate sales into markets where the seller has
not been found to have market power, we do not
agree that it is reasonable to allow a mitigated seller
to make market-based rate sales anywhere within a
mitigated market. It is unrealistic to believe that
sales made anywhere in a balancing authority area
can be traced to ensure that no improper sales are
taking place. Such an approach would also place
customers and competitors at an unreasonable
disadvantage because the mitigated seller has
dominance in the very market in which it is making
market-based rate sales.’’ Id.; see also Westar
Energy, Inc. v. FERC, No. 08–1196, slip op. at 5
(D.C. Cir. June 12, 2009) (stating that in Order No.
697 the Commission concluded that ‘‘it ‘is
unrealistic to believe that’ such sales ‘can be traced
to ensure that no improper sales are taking place.’ ’’)
(citation omitted); Order No. 697–A, FERC Stats. &
Regs. ¶ 31,268 at P 321.
79 See Order No. 697–A, FERC Stats. & Regs.
¶ 31,268 at P 335.
80 Id. P 336.

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provision adopted in Order No. 697–B
interferes with must-offer and reliability
requirements, reserve sharing
agreements, and cost-based requirement
contracts, we note that if a mitigated
seller does not make market-based rate
sales at the border, either that mitigated
seller or its affiliates may make sales at
cost-based rates into the balancing
authority area in which it is mitigated.
A mitigated seller can perform each of
the above-enumerated functions either
by selling at cost-based rates within its
restricted balancing authority area,
selling at cost-based rates at the metered
boundary of its restricted balancing
authority area, or by selling at marketbased rates at the metered boundary as
long as it makes sure that title to the
power sold transfers at or beyond the
metered boundary. Moreover, we note
that our restrictions on sales at the
border only apply to new agreements
that the seller enters into prospective
from the date that Order No. 697–B
became effective. No existing
agreements are upset or need to be
revised in any way provided that the
seller abides by our restrictions on any
new agreements that it enters into
prospectively. Of the rehearing requests
that have been filed in this proceeding
on this issue, none have identified in
this rehearing why it is burdensome or
unreasonably costly for sellers to enter
into new power sales agreements where
title transfers at or beyond the metered
boundary between the mitigated and
non-mitigated balancing authority
areas.81 Given that many petitioners
have acknowledged that the approaches
in Order No. 697 and 697–A would be
extremely difficult to enforce because
even the sellers themselves cannot
guarantee that power sold on the seller’s
side of the metered boundary will not
somehow find its way back into the
restricted market, we do not believe it
is appropriate to return to a rule that is
difficult not only for sellers to comply
with but also for the Commission to
enforce. Such an impracticable rule will
not enable the Commission to ensure
that market power is not being exercised
in the restricted market.
44. With respect to petitioners’
requests that the Commission return to
the intent-based concept first used in
Order No. 697, we note that in Order
81 As the Court of Appeals for the District of
Columbia Circuit recently confirmed, ‘‘a wholesaler
* * * can easily comply with the [Commission]
rule and still make sales into other regions at
market-based rates. A wholesaler simply needs to
ensure that title passes at or beyond the metered
boundary between the mitigated and non-mitigated
areas, instead of inside a mitigated area.’’ Westar
Energy, Inc. v. FERC, No. 08–1196, slip op. at 5
(D.C. Cir. June 12, 2009) (citation omitted).

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Federal Register / Vol. 74, No. 123 / Monday, June 29, 2009 / Rules and Regulations
No. 697–A, the Commission revised the
mitigated sales tariff provision to
remove the intent element in response
to petitioners’ requests, including
Pinnacle, who questioned how the
Commission could ensure that a
mitigated seller knows what an
unaffiliated buyer intends to do with
power, and complained that it is
difficult and administratively
burdensome to determine and document
intent.82 In Order No. 697–A, the
Commission agreed with petitioners that
it would be difficult to determine and
document intent, and therefore decided
to eliminate the intent element of the
tariff provision. On rehearing of Order
No. 697–B, petitioners have not
provided any new arguments that
persuade us that returning to the intentbased concept first used in Order No.
697 will not present the same problems
regarding the ability to determine and
document intent.
45. In addition, the mitigated sales
tariff provision in Appendix C of Order
Nos. 697–A and 697–B inadvertently
omitted language that was included in
the provision adopted in Order No. 697.
Accordingly, we will revise the tariff
provision for market-based rate sales at
the metered boundary as follows (bold
font indicates new text):
Sales of energy and capacity are
permissible under this tariff in all balancing
authority areas where the Seller has been

granted market-based rate authority. Sales of
energy and capacity under this tariff are also
permissible at the metered boundary between
the Seller’s mitigated balancing authority
area and a balancing authority area where the
Seller has been granted market-based rate
authority provided: (i) Legal title of the
power sold transfers at the metered boundary
of the balancing authority area where the
seller has market-based rate authority; and
(ii) if the Seller sells at the metered boundary
of a mitigated balancing authority area at
market-based rates, then neither it nor its
affiliates can sell into that mitigated
balancing authority area from the outside.
Seller must retain, for a period of five years
from the date of the sale, all data and
information related to the sale that
demonstrates compliance with items (i) and
(ii) above.

46. Sellers that have already adopted
the tariff language prescribed in Order
No. 697–B are directed to revise the
provision in accordance with this order
on the next occasion when they
otherwise would be required to file
revised tariff sheets with the
Commission, a change in status filing, or
triennial review.83
C. Implementation Process
Clarifications on Implementation
Process
Background
47. In Order No. 697, to ensure greater
consistency in the data used to evaluate
Category 2 sellers, the Commission

30933

modified the timing for the submission
of updated market power analyses.
Order No. 697 requires analyses to be
filed for each seller’s region on a predetermined schedule, rotating by
geographic region where two regions are
reviewed each year, with the cycle
repeating every three years.84 In Order
No. 697–A, the Commission provided
additional guidance regarding the
implementation process. In particular, it
explained that in the December 14
Clarification Order, it clarified that
‘‘transmission-owning utilities with
market-based rate authority and their
affiliates with market-based rate
authority are the entities required to file
their updated market power analyses
first in each region.’’ 85 Accordingly, in
Order No. 697–A, the Commission
revised Appendix D to make clear that
transmission owners and their affiliates
have earlier filing periods than other
entities required to file in each region.86
48. Upon further review of the
Schedule for All Other Entities provided
at Appendix D–2 to Order No. 697–A,
it has come to our attention that the list
of entities required to file updated
market power analyses omits the 2010
filing dates for Southwest and
Northwest non-transmission owning
entities.87 Accordingly, we will revise
Appendix D to add the following:
Appendix D—2

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SCHEDULE FOR ALL OTHER ENTITIES
Entities required to file

Filing period
(anytime during the month)

Others in Southwest that did not file in December and have not been
found to be Category 1 sellers.
Others in Northwest that did not file in June and have not been found to
be Category 1 sellers.

June 2010 ........................................

Dec. 1, 2009–Nov. 30, 2010.

December 2010 ................................

Dec. 1, 2009–Nov. 30, 2010.

Street, NE., Room 2A, Washington, DC
20426.
51. From FERC’s Home Page on the
V. Document Availability
Internet, this information is available on
eLibrary. The full text of this document
50. In addition to publishing the full
is available on eLibrary in PDF and
text of this document in the Federal
Microsoft Word format for viewing,
Register, the Commission provides all
printing, and/or downloading. To access
interested persons an opportunity to
this document in eLibrary, type the
view and/or print the contents of this
docket number excluding the last three
document via the Internet through
FERC’s Home Page (http://www.ferc.gov) digits of this document in the docket
number field.
and in FERC’s Public Reference Room
52. User assistance is available for
during normal business hours (8:30 a.m.
eLibrary and the FERC’s Web site during
to 5 p.m. Eastern time) at 888 First

IV. Information Collection Statement
49. The Office of Management and
Budget (OMB) regulations require that
OMB approve certain information
collection requirements imposed by an
agency.88 The Final Rule’s revisions to
the information collection requirements
for market-based rate sellers were
approved under OMB Control No. 1902–
0234. While this order clarifies aspects
of the existing information collection
requirements for the market-based rate
program, it does not add to these
requirements. Accordingly, a copy of

this order will be sent to OMB for
informational purposes only.

82 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at P 334.
83 The revised tariff language set forth in the
paragraph above is effective as of the effective date
of Order No. 697–A.

84 See Order No. 697, FERC Stats. & Regs. ¶
31,252 at Appendix D. The regions include the
Northeast, Southeast, Central, Southwest Power
Pool, Southwest, and Northwest.
85 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at P 374 (citing December 14 Clarification Order,
121 FERC ¶ 61,260 at P 9) (emphasis in original).

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86 Id.
87 These entities were included in the Regional
Market Power Update Schedule provided in
Appendix D to Order No. 697.
88 5 CFR 1320.11.

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Federal Register / Vol. 74, No. 123 / Monday, June 29, 2009 / Rules and Regulations

normal business hours from FERC
Online Support at 202–502–6652 (toll
free at 1–866–208–3676) or e-mail at
[email protected], or the
Public Reference Room at (202) 502–
8371, TTY (202) 502–8659. E-mail the
Public Reference Room at
[email protected].
VI. Effective Date
53. Changes adopted in this order on
rehearing will become effective July 29,
2009.
List of Subjects in 18 CFR Part 35
Electric power rates, Electric utilities,
Reporting and recordkeeping
requirements by the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

In consideration of the foregoing, the
Commission amends part 35 Chapter I,
Title 18, Code of Federal Regulations, as
follows:
■

PART 35—FILING OF RATE
SCHEDULES AND TARIFFS
1. The authority citation for part 35
continues to read as follows:

■

Authority: 16 U.S.C. 791a–825r, 2601–
2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352.

2. Section 35.42 is revised to read as
follows:

■

§ 35.42 Change in status reporting
requirement.

(a) As a condition of obtaining and
retaining market-based rate authority, a
Seller must timely report to the
Commission any change in status that
would reflect a departure from the
characteristics the Commission relied
upon in granting market-based rate
authority. A change in status includes,
but is not limited to, the following:
(1) Ownership or control of generation
capacity that results in net increases of
100 MW or more, or of inputs to electric
power production, or ownership,
operation or control of transmission
facilities, or
(2) Affiliation with any entity not
disclosed in the application for marketbased rate authority that owns or
controls generation facilities or inputs to
electric power production, affiliation
with any entity not disclosed in the

application for market-based rate
authority that owns, operates or controls
transmission facilities, or affiliation
with any entity that has a franchised
service area.
(b) Any change in status subject to
paragraph (a) of this section, other than
a change in status submitted to report
the acquisition of control of a site or
sites for new generation capacity
development, must be filed no later than
30 days after the change in status
occurs. Power sales contracts with
future delivery are reportable 30 days
after the physical delivery has begun.
Failure to timely file a change in status
report constitutes a tariff violation.
(c) When submitting a change in
status notification regarding a change
that impacts the pertinent assets held by
a Seller or its affiliates with marketbased rate authorization, a Seller must
include an appendix of assets in the
form provided in Appendix B of this
subpart.
(d) A Seller must report on a quarterly
basis the acquisition of control of a site
or sites for new generation capacity
development for which site control has
been demonstrated in the
interconnection process and for which
the potential number of megawatts that
are reasonably commercially feasible on
the site or sites for new generation
capacity development is equal to 100
megawatts or more. If a Seller elects to
make a monetary deposit so that it may
demonstrate site control at a later time
in the interconnection process, the
monetary deposit will trigger the
quarterly reporting requirement instead
of the demonstration of site control. A
notification of change in status that is
submitted to report the acquisition of
control of a site or sites for new
generation capacity development must
include:
(1) The number of sites acquired;
(2) The relevant geographic market in
which the sites are located; and
(3) The maximum potential number of
megawatts (MW) that are reasonably
commercially feasible on the sites
reported.
(e) A Seller must report to the
Commission any land it has acquired,
taken a leasehold interest in, obtained
an option to purchase or lease, or

entered into an exclusivity or other
arrangement to acquire for new
generation capacity development and
for which site control has not yet been
demonstrated during the prior three
years (triggering event), and for which
the potential number of megawatts that
are reasonably commercially feasible on
the land for new generation capacity
development is equal to 100 megawatts
or more. A Seller must report each such
triggering event in a single report by
January 1 of the year following the
calendar year in which the triggering
event occurred. The information that
must be provided and the aggregation of
the maximum potential number of
megawatts by relevant geographic
market is the same as required in the
quarterly reports, as described in
paragraph (d) of this section.
(f) For the purposes of paragraph (d)
of this section, ‘‘control’’ shall mean
‘‘site control’’ as it is defined in the
Standard Large Generator
Interconnection Procedures (LGIP).
Note: The following appendix will not be
published in the Code of Federal Regulations.

Appendix C to Order No. 697–C
*

*

*

*

*

Mitigated Sales
Sales of energy and capacity are
permissible under this tariff in all balancing
authority areas where the Seller has been
granted market-based rate authority. Sales of
energy and capacity under this tariff are also
permissible at the metered boundary between
the Seller’s mitigated balancing authority
area and a balancing authority area where the
Seller has been granted market-based rate
authority provided: (i) Legal title of the
power sold transfers at the metered boundary
of the balancing authority area where the
seller has market-based rate authority; and
(ii) if the Seller sells at the metered boundary
of a mitigated balancing authority area at
market-based rates, then neither it nor its
affiliates can sell into that mitigated
balancing authority area from the outside.
Seller must retain, for a period of five years
from the date of the sale, all data and
information related to the sale that
demonstrates compliance with items (i) and
(ii) above.

*

*

*

*

*

Appendix D–2

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SCHEDULE FOR ALL OTHER ENTITIES
Filing period
(anytime during
the month)

Entities required to file
All others in Northeast that did not file in December including all power
marketers that sold in the Northeast.

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Federal Register / Vol. 74, No. 123 / Monday, June 29, 2009 / Rules and Regulations

30935

SCHEDULE FOR ALL OTHER ENTITIES—Continued
Filing period
(anytime during
the month)

Entities required to file
All others in Southeast that did not file in June including all power marketers that sold in the Southeast and have not already been found to
be Category 1 sellers.
All others in Central that did not file in December including all power marketers that sold in the Central and have not already been found to be
Category 1 sellers.
All others in SPP that did not file in June including all power marketers
that sold in SPP and have not already been found to be Category 1
sellers.
Others in Southwest that did not file in December and have not been
found to be Category 1 sellers.
Others in Northwest that did not file in June and have not been found to
be Category 1 sellers.
Others in Northeast that did not file in December and have not been
found to be Category 1 sellers.
Others in Southeast that did not file in June and have not been found to
be Category 1 sellers.
Others in Central that did not file in December and have not been found
to be Category 1 sellers.
Others in SPP that did not file in June and have not been found to be
Category 1 sellers.
Others in Southwest that did not file in December and have not been
found to be Category 1 sellers.
Others in Northwest that did not file in June and have not been found to
be Category 1 sellers.

[FR Doc. E9–14784 Filed 6–26–09; 8:45 am]
BILLING CODE 6717–01–P

Coast Guard
33 CFR Part 1
46 CFR Part 1
[USCG–2009–0314]
RIN 1625–ZA22

Establishment of Suspension and
Revocation National Center of
Expertise
Coast Guard, DHS.
Final rule.

AGENCY:

cprice-sewell on PRODPC61 with RULES

SUMMARY: This rule makes nonsubstantive, technical changes to Titles
33 and 46 of the CFR to reflect the
authorization and establishment of the
Coast Guard Suspension and Revocation
National Center of Expertise (S&R
NCOE). The S&R NCOE is responsible
for performing suspension and
revocation functions regarding
Merchant Mariner Credentials.
Investigating Officers (IOs), both
military and civilian employees, are
assigned to the S&R NCOE for this
purpose. These changes affect internal
Coast Guard organization and
functioning only and will have no

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Dec. 1, 2005–Nov. 30, 2006.

June 2009 ........................................

Dec. 1, 2006–Nov. 30, 2007.

December 2009 ................................

Dec. 1, 2006–Nov. 30, 2007.

June 2010 ........................................

Dec. 1, 2009–Nov. 30, 2010.

December 2010 ................................

Dec. 1, 2009–Nov. 30, 2010.

June 2011 ........................................

Dec. 1, 2008–Nov. 30, 2009.

December 2011 ................................

Dec. 1, 2008–Nov. 30, 2009.

June 2012 ........................................

Dec. 1, 2009–Nov. 30, 2010.

December 2012 ................................

Dec. 1, 2009–Nov. 30, 2010.

June 2013 ........................................

Dec. 1, 2010–Nov. 30, 2011.

December 2013 ................................

Dec. 1, 2010–Nov. 30, 2011.

Effective on June 29, 2009.

Documents mentioned in
this preamble as being available in the
docket, are part of USCG–2009–0314
and are available online by going to
http://www.regulations.gov, selecting
the Advanced Docket Search option on
the right side of the screen, inserting
USCG–2009–0314 in the Docket ID box,
pressing Enter, and then clicking on the
item in the Docket ID column. They are
also available for inspection or copying
at two locations: The Docket
Management Facility (M–30), U.S.
Department of Transportation, West
Building Ground Floor, Room W12–140,
1200 New Jersey Avenue, SE.,
Washington, DC 20590, between 9 a.m.
and 5 p.m., Monday through Friday,
except Federal Holidays, and at S&R
COE co-located with the National
Maritime Center, 100 Forbes Drive,
Martinsburg, WV between 9 a.m. and 5
p.m., Monday through Friday, except
Federal holidays.

ADDRESSES:

DEPARTMENT OF HOMELAND
SECURITY

ACTION:

December 2008 ................................

substantive effect on mariners or other
members of the public.
DATES:

FOR FURTHER INFORMATION CONTACT: If
you have questions on this rule, call
Commander Scott Budka, Supervisor,
S&R NCOE, U.S. Coast Guard, telephone
304–433–3744. If you have questions on
viewing the docket, call Ms. Renee V.
Wright, Program Manager, Docket
Operations, telephone or 202–366–9826.
SUPPLEMENTARY INFORMATION:

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Regulatory Information
The Coast Guard is issuing this final
rule without prior notice and
opportunity to comment pursuant to
authority under section 4(a) of the
Administrative Procedure Act (APA) (5
U.S.C. 553(b)). This provision
authorizes an agency to issue a rule,
without prior notice and opportunity to
comment, when the agency for good
cause finds that those procedures are
‘‘impracticable, unnecessary, or contrary
to the public interest.’’ Under 5 U.S.C.
553(b)(B), the Coast Guard finds that
good cause exists for not publishing a
notice of proposed rulemaking (NPRM)
with respect to this rule because is
unnecessary. This rulemaking makes
amendments to rules regarding agency
organization and functioning. As such,
comments are unnecessary because they
would not change the Coast Guard’s
internal delegation of authority and
duty regarding the Suspension and
Revocation process or provide
additional expertise regarding Coast
Guard functioning.
Under 5 U.S.C. 553(d)(3), the Coast
Guard finds that good cause exists for
making this rule effective less than 30
days after publication in the Federal
Register because these changes affect
internal Coast Guard organization and
functioning only and will have no
substantive effect on the public.

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