Essential Reliability Services and the Evolving Bulk-Power System-Primary Frequency Response, 85176-85190 [2016-28321]
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By direction of the Commission.
Issued: November 17, 2016.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
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DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 35
[Docket No. RM16–6–000]
Essential Reliability Services and the
Evolving Bulk-Power System—Primary
Frequency Response
Federal Energy Regulatory
Commission, Department of Energy.
ACTION: Notice of proposed rulemaking.
AGENCY:
The Federal Energy
Regulatory Commission (Commission)
proposes to revise its regulations to
require all newly interconnecting large
and small generating facilities, both
synchronous and non-synchronous, to
install and enable primary frequency
response capability as a condition of
interconnection. To implement these
requirements, the Commission proposes
to revise the pro forma Large Generator
Interconnection Agreement (LGIA) and
the pro forma Small Generator
Interconnection Agreement (SGIA). The
proposed changes are designed to
address the increasing impact of the
evolving generation resource mix and to
ensure that the relevant provisions of
the pro forma LGIA and pro forma SGIA
are just, reasonable, and not unduly
discriminatory or preferential. The
Commission also seeks comment on
whether its proposals in this Notice of
Proposed Rulemaking are sufficient at
this time to ensure adequate levels of
primary frequency response, or whether
additional reforms are needed.
DATES: Comments are due January 24,
2017.
SUMMARY:
Comments, identified by
docket number, may be filed in the
following ways:
• Electronic Filing through https://
www.ferc.gov. Documents created
electronically using word processing
software should be filed in native
applications or print-to-PDF format and
not in a scanned format.
• Mail/Hand Delivery: Those unable
to file electronically may mail or handdeliver comments to: Federal Energy
Regulatory Commission, Secretary of the
Commission, 888 First Street NE.,
Washington, DC 20426.
Instructions: For detailed instructions
on submitting comments and additional
information on the rulemaking process,
see the Comment Procedures Section of
this document.
FOR FURTHER INFORMATION CONTACT:
Jomo Richardson (Technical
Information), Office of Electric
ADDRESSES:
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Reliability, Federal Energy Regulatory
Commission, 888 First Street NE.,
Washington, DC 20426, (202) 502–
6281, Jomo.Richardson@ferc.gov.
Mark Bennett (Legal Information), Office
of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street NE., Washington, DC
20426, (202) 502–8524,
Mark.Bennett@ferc.gov.
SUPPLEMENTARY INFORMATION:
1. In this Notice of Proposed
Rulemaking (NOPR), the Federal Energy
Regulatory Commission (Commission)
proposes to modify the pro forma Large
Generator Interconnection Agreement
(LGIA) and the pro forma Small
Generator Interconnection Agreement
(SGIA), pursuant to its authority under
section 206 of the Federal Power Act
(FPA) to ensure that rates, terms and
conditions of jurisdictional service
remain just and reasonable and not
unduly discriminatory or preferential.1
The proposed modifications would
require all new large and small
generating facilities, including both
synchronous and non-synchronous,
interconnecting with a LGIA or SGIA to
install, maintain and operate equipment
capable of providing primary frequency
response as a condition of
interconnection. The Commission also
proposes to establish certain operating
requirements, including maximum
droop and deadband parameters in the
pro forma LGIA and pro forma SGIA.
The Commission does not propose to
apply these requirements to generating
facilities regulated by the Nuclear
Regulatory Commission. In addition, the
Commission does not propose in these
reforms to impose a headroom
requirement for new generating
facilities. The Commission also does not
propose to mandate that new generating
facilities receive any compensation for
complying with the proposed
requirements in this NOPR.
2. The proposed revisions address the
Commission’s concerns that the existing
pro forma LGIA contains limited
primary frequency response
requirements that apply only to
synchronous generating facilities and do
not account for recent technological
advancements that have enabled new
non-synchronous generating facilities to
now have primary frequency response
capabilities. Further, the Commission
believes that it may be unduly
discriminatory or preferential to impose
primary frequency response
requirements only on new large
generating facilities but not on new
small generating facilities, and the
reforms proposed here would impose
1 16
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comparable primary frequency response
requirements on both new large and
small generating facilities.
3. In addition, and as discussed below
in paragraph 57, the Commission also
seeks comment on whether its proposals
in this NOPR are sufficient at this time
to ensure adequate levels of primary
frequency response, or whether
additional reforms are needed.
4. The Commission seeks comment on
the proposed reforms and requests for
comment sixty (60) days after
publication of this NOPR in the Federal
Register.
I. Background
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A. Frequency Response
5. Reliable operation of an
Interconnection 2 depends on
maintaining frequency within
predetermined boundaries above and
below a scheduled value, which is 60
Hertz (Hz) in North America. Changes in
frequency are caused by changes in the
balance between load and generation,
such as the sudden loss of a large
generator or a large amount of load. If
frequency deviates too far above or
below its scheduled value, it could
potentially result in under frequency
load shedding (UFLS), generation
tripping, or cascading outages.3
6. Mitigation of frequency deviations
after the sudden loss of generation or
load is driven by three primary factors:
inertial response, primary frequency
response, and secondary frequency
response.4 Primary frequency response
actions begin within seconds after
system frequency changes and are
mostly provided by the automatic and
autonomous actions (i.e., outside of
system operator control) of turbine2 An Interconnection is a geographic area in
which the operation of the electric system is
synchronized. In the continental United States,
there are three Interconnections, namely the
Eastern, Texas, and Western Interconnections.
3 UFLS is designed for use in extreme conditions
to stabilize the balance between generation and
load. Under frequency protection schemes are
drastic measures employed if system frequency falls
below a specified value. See Automatic
Underfrequency Load Shedding and Load Shedding
Plans Reliability Standards, Notice of Proposed
Rulemaking, FERC Stats. & Regs. ¶ 32,682, at PP 4–
10 (2011) (Order No. 763 NOPR) at PP 4–10.
4 In the Notice of Inquiry issued in Docket No.
RM16–6–000 on Feb. 8, 2016, the Commission
provided detailed discussion of how inertia,
primary frequency response, and secondary
frequency response interact to mitigate frequency
deviations. Essential Reliability Services and the
Evolving Bulk-Power System—Primary Frequency
Response, 154 FERC ¶ 61,117, at PP 3–7 (2016)
(NOI). See also Use of Frequency Response Metrics
to Assess the Planning and Operating Requirements
for Reliable Integration of Variable Renewable
Generation, Lawrence Berkeley National
Laboratory, at 13–14 (Dec. 2010), https://
energy.lbl.gov/ea/certs/pdf/lbnl-4142e.pdf (LBNL
2010 Report).
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governors, while some response is
provided by frequency responsive
loads.5 Primary frequency response
actions are intended to arrest abnormal
frequency deviations and ensure that
system frequency remains within
acceptable bounds. An important goal
for system planners and operators is for
the frequency nadir,6 during large
disturbances, to remain above the first
stage of UFLS set points within an
Interconnection.
7. Frequency response is a measure of
an Interconnection’s ability to arrest and
stabilize frequency deviations following
the sudden loss of generation or load,
and is affected by the collective
responses of generation and load
throughout the Interconnection. When
considered in aggregate, the primary
frequency response provided by
generators within an Interconnection
has a significant impact on the overall
frequency response. NERC Reliability
Standard BAL–003–1.1 defines the
amount of frequency response needed
from balancing authorities 7 to maintain
Interconnection frequency within
predefined bounds and includes
requirements for the measurement and
provision of frequency response.8 While
NERC Reliability Standard BAL–003–
1.1 establishes requirements for
balancing authorities, it does not
include any requirements for individual
generator owners or operators.9
5 NOI, 154 FERC ¶ 61,117 at P 6. The Commission
also noted that regulation service is different than
primary frequency response because generating
facilities that provide regulation respond to
automatic generation control signals and regulation
service is centrally coordinated by the system
operator, whereas primary frequency response
service, in contrast, is autonomous and is not
centrally coordinated. Schedule 3 of the pro forma
Open Access Transmission Tariff (OATT) bundles
these different services together, despite their
differences. See Id. n.66.
6 The point at which the frequency decline is
arrested (following the sudden loss of generation)
is called the frequency nadir, and represents the
point at which the net primary frequency response
(real power) output from all generating units and
the decrease in power consumed by the load within
an Interconnection matches the net initial loss of
generation (in megawatts (MW)).
7 NERC’s Glossary of Terms defines a balancing
authority as ‘‘(t)he responsible entity that integrates
resource plans ahead of time, maintains loadinterchange-generation balance within a balancing
authority area, and supports Interconnection
frequency in real time.’’
8 Frequency Response and Frequency Bias Setting
Reliability Standard, Order No. 794, 146 FERC ¶
61,024 (2014).
9 The Commission has also accepted Regional
Reliability Standard BAL–001–TRE–01 (Primary
Frequency Response in the ERCOT Region) as
mandatory and enforceable, which does establish
requirements for generator owners and operators
with respect to governor control settings and the
provision of primary frequency response within the
Electric Reliability Council of Texas (ERCOT)
region. North American Electric Reliability
Corporation, 146 FERC ¶ 61,025 (2014).
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8. Unless otherwise required by tariffs
or interconnection agreements,
generator owners and operators can
independently decide whether units are
configured to provide primary
frequency response.10 The magnitude
and duration of a generator’s response to
frequency deviations is generally
determined by the settings of the unit’s
governor 11 (or equivalent controls) and
other plant level (e.g., ‘‘outer-loop’’)
control systems. In particular, the
governor’s droop and deadband settings
have a significant impact on the unit’s
provision of primary frequency
response. In addition, plant-level or
‘‘outer-loop’’ controls, unless properly
configured, can override or nullify a
generator’s governor response and
return the unit to operate at a scheduled
pre-disturbance megawatt set-point.12 In
2010, NERC conducted a survey of
generator owners and operators and
found that only approximately 30
percent of generators in the Eastern
Interconnection provided primary
frequency response, and that only
approximately 10 percent of generators
provided sustained primary frequency
response.13 This suggests that many
generators within the Interconnection
disable or otherwise set their governors
or outer-loop controls such that they
provide little to no primary frequency
response.14
9. Declining frequency response
performance has been an industry
concern for many years. NERC, in
conjunction with EPRI, initiated its first
examination of declining frequency
response and governor response in
1991.15 More recently, as noted in the
10 See
NOI, 154 FERC ¶ 61,117 at PP 18–19.
governor is an electronic or mechanical
device that implements primary frequency response
on a generator via a droop parameter. Droop refers
to the variation in real power (MW) output due to
variations in system frequency and is typically
expressed as a percentage (e.g., 5 percent droop).
Droop reflects the amount of frequency change from
nominal (e.g., 5 percent of 60 Hz is 3 Hz) that is
necessary to cause the main prime mover control
mechanism of a generating facility to move from
fully closed to fully open. A governor also has a
deadband parameter which establishes a minimum
frequency deviation (e.g., ±0.036 Hz) from nominal
that must be exceeded in order for the governor to
act.
12 For more discussion on ‘‘premature
withdrawal’’ of primary frequency response, see
NOI, 154 FERC ¶ 61,117 at PP 49–50.
13 See NERC Frequency Response Initiative
Report: The Reliability Role of Frequency Response
(Oct. 2012), https://www.nerc.com/docs/pc/FRI_
Report_10-30-12_Master_w-appendices.pdf (NERC
Frequency Response Initiative Report) at 95.
14 However, as noted below, some commenters
note that nuclear generating units are restricted by
their U.S. Nuclear Regulatory Commission
operating licenses regarding the provision of
primary frequency response.
15 NERC Frequency Response Initiative Report at
22.
11 A
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NOI, while the three U.S.
Interconnections currently exhibit
adequate frequency response
performance above their
Interconnection Frequency Response
Obligations,16 there has been a
significant decline in the frequency
response performance of the Western
and Eastern Interconnections.17
B. Prior Commission Actions
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10. In Order Nos. 2003 18 and 2006,19
the Commission adopted standard
procedures for the interconnection of
large and small generating facilities,
including the development of
standardized pro forma generator
interconnection agreements and
procedures. The Commission required
public utility transmission providers 20
to file revised OATTs containing these
standardized provisions, and use the
LGIA and SGIA to provide nondiscriminatory interconnection service
to Large Generators (i.e., generating
facilities having a capacity of more than
20 MW) and Small Generators (i.e.,
generators having a capacity of no more
than 20 MW). The pro forma LGIA and
pro forma SGIA have since been revised
through various subsequent
proceedings.21
16 The Interconnection Frequency Response
Obligations are established by NERC and are
designed to require sufficient frequency response
for each Interconnection (i.e., the Eastern, ERCOT,
Quebec and Western Interconnections) to arrest
frequency declines even for severe, but possible,
contingencies.
17 NOI, 154 FERC ¶ 61,117 at P 20.
18 Standardization of Generator Interconnection
Agreements and Procedures, Order No. 2003, FERC
Stats. & Regs. ¶ 31,146 (2003), order on reh’g, Order
No. 2003–A, FERC Stats. & Regs. ¶ 31,160, order on
reh’g, Order No. 2003–B, FERC Stats. & Regs. ¶
31,171 (2004), order on reh’g, Order No. 2003–C,
FERC Stats. & Regs. ¶ 31,190 (2005), aff’d sub nom.
Nat’l Ass’n of Regulatory Util. Comm’rs v. FERC,
475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552
U.S. 1230 (2008).
19 Standardization of Small Generator
Interconnection Agreements and Procedures, Order
No. 2006, FERC Stats. & Regs. ¶ 31,180, order on
reh’g, Order No. 2006–A, FERC Stats. & Regs. ¶
31,196 (2005), order granting clarification, Order
No. 2006–B, FERC Stats. & Regs. ¶ 31,221 (2006).
20 A public utility is a utility that owns, controls,
or operates facilities used for transmitting electric
energy in interstate commerce, as defined by the
FPA. See 16 U.S.C. 824(e) (2012). A non-public
utility that seeks voluntary compliance with the
reciprocity condition of an OATT may satisfy that
condition by filing an OATT, which includes a
LGIA and SGIA. See Order No. 2003, FERC Stats.
& Regs. ¶ 31,146, at PP 840–845.
21 E.g., Small Generator Interconnection
Agreements and Procedures, Order No. 792, 145
FERC ¶ 61,159 (2013), clarifying, Order No. 792–A,
146 FERC ¶ 61,214 (2014); Reactive Power
Requirements for Non-Synchronous Generation,
Order No. 827, 81 FR 40,793 (Jun. 23, 2016), 155
FERC ¶ 61,277 (2016); Requirements for Frequency
and Voltage Ride Through Capability of Small
Generating Facilities, Order No. 828, 81 FR 50,290
(Aug. 1, 2016), 156 FERC ¶ 61,062 (2016).
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11. As relevant here, the pro forma
LGIA and pro forma SGIA are largely
silent on any requirements with respect
to primary frequency response. In
particular, the only requirement in the
pro forma LGIA or pro forma SGIA
related to primary frequency response is
contained within current Article 9.6.2.1
of the pro forma LGIA (Governors and
Regulators), which provides that if
speed governors are installed, they
should be operated in automatic
mode.22 A speed governor implements
the primary frequency response
provided by a synchronous generating
facility; however, Article 9.6.2.1 does
not address governor settings or plantlevel controls, which also affect the
ability of a generating facility to provide
primary frequency response. In
addition, Article 9.6.2.1 does not require
the installation of the necessary
equipment for frequency response
capability (i.e., governors or equivalent
controls). Finally, the pro forma SGIA
does not contain any provisions related
to primary frequency response.
C. Efforts To Evaluate the Impacts of the
Changing Resource Mix
12. The Commission’s pro forma
generator interconnection agreements
and procedures were developed at a
time when traditional synchronous
generating facilities with standard
governor controls and large rotational
inertia were the predominant sources of
electricity generation. However, the
nation’s resource mix has undergone
significant change since the issuance of
Order Nos. 2003 and 2006. This
transformation has been characterized
by the retirement of baseload,
synchronous generating facilities and
the integration of more distributed
generation, demand response, and
natural gas generating facilities, and the
rapid expansion of non-synchronous
variable energy resources (VERs) such as
wind and solar.23 For example, the U.S.
Energy Information Administration
(EIA) has observed that the U.S. added
approximately 13 gigawatts (GW) of
wind, 6.2 GW of utility scale solar
photovoltaic (PV), and 3.6 GW of
distributed solar PV generating facilities
in 2014 and 2015.24 Conversely, NERC
22 Article
9.6.2.1 of the pro forma LGIA.
term VER is defined as a device for the
production of electricity that is characterized by an
energy source that: (1) Is renewable; (2) cannot be
stored by the facility owner or operator; and (3) has
variability that is beyond the control of the facility
owner or operator. See, e.g., Integration of Variable
Energy Resources, Order No. 764, FERC Stats. &
Regs. ¶ 31,331, at P 210 (2012).
24 See, U.S. electric generation capacity additions,
2015 vs. 2014, EIA (March 2016), https://
www.eia.gov/todayinenergy/detail.php?id=25492.
23 The
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has reported 25 that almost 42 GW of
synchronous generating facilities (e.g.,
coal, nuclear, and natural gas) have
retired between 2011 and 2014, and the
EIA recently reported that nearly 14 GW
of coal and 3 GW of natural gas
generating facilities retired in 2015.26
13. While technological
advancements have enabled wind and
solar generating facilities to now have
the ability to provide primary frequency
response, this functionality has not
historically been a standard feature that
was included and enabled on nonsynchronous generating facilities.
Moreover, wind and solar generating
facilities typically operate at their
maximum operating output, leaving no
capacity (or ‘‘headroom’’) 27 to provide
primary frequency response during
under-frequency conditions.
14. Given the changes in the resource
mix and concerns about the significant
decline in frequency response for the
Eastern and Western Interconnections,28
NERC has undertaken several initiatives
to evaluate the impacts of the changing
resource mix, particularly with respect
to primary frequency response. For
example, in 2014, NERC initiated the
Essential Reliability Services Task Force
(Task Force) to analyze and better
understand the impacts of the changing
resource mix and develop technical
assessments of essential reliability
services.29 The Task Force focused on
three essential reliability services:
Frequency support, ramping capability,
and voltage support.30 The Task Force
considered the seven ancillary
25 See NERC 2015 LTRA (Dec. 2015), https://
www.nerc.com/pa/RAPA/ra/
Reliability%20Assessments%20DL/2015LTRA%20%20Final%20Report.pdf.
26 See Electricity generating capacity retired in
2015 by fuel and technology, EIA (May 2016),
https://www.eia.gov/todayinenergy/
detail.php?id=25272.
27 Headroom refers to the difference between the
current operating point of a generator and its
maximum operating capability, and represents the
potential amount of additional energy that can be
provided by the generating facility in real-time.
28 See NERC Frequency Response Initiative
Industry Advisory—Generator Governor Frequency
Response, at slide 10 (Apr. 2015), https://
www.nerc.com/pa/rrm/Webinars%20DL/Generator_
Governor_Frequency_Response_Webinar_April_
2015.pdf. (NERC 2015 Frequency Response
Webinar). See also LBNL 2010 Report at pp xiv–xv.
29 Essential reliability services are referred to as
elemental reliability building blocks from resources
(generation and load) that are necessary to maintain
the reliability of the Bulk-Power System. See
Essential Reliability Services Task Force Scope
Document, at 1 (Apr. 2014), https://www.nerc.com/
comm/Other/essntlrlbltysrvcstskfrcDL/Scope_
ERSTF_Final.pdf.
30 Essential Reliability Services Task Force
Measures Report, at 22 (Dec. 2015), https://
www.nerc.com/comm/Other/essntlrlblty
srvcstskfrcDL/ERSTF%20Framework%20Report
%20-%20Final.pdf.
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services 31 adopted by the Commission
in Order Nos. 888 32 and 890 33 as a
subset of the essential reliability
services that may need to be augmented
by additional services as the Bulk-Power
System 34 characteristics change.
15. The Task Force did not
recommend new reliability standards or
specific actions to alter the existing
suite of ancillary services; however, it
did make certain conclusions with
regard to primary frequency response.
Specifically, the Task Force concluded
that it is prudent and necessary to
ensure that primary frequency response
capabilities are present in the future
generation resource mix, and
recommended that all new generators
support the capability to manage
frequency.35
16. In addition, as part of its ongoing
analysis of primary frequency response
concerns, NERC observed in a 2012
report that a number of generators
implemented deadband settings that
were so wide as to effectively defeat the
ability to provide primary frequency
response.36 The report also notes that
many generators provide frequency
response in the wrong direction during
31 The seven pro forma ancillary services set forth
in Order Nos. 888 and 890 are: (1) Scheduling,
System Control and Dispatch Service; (2) Reactive
Supply and Voltage Control from Generation
Sources Service; (3) Regulation and Frequency
Response Service; (4) Energy Imbalance Service; (5)
Operating Reserve—Spinning Reserve Service; (6)
Operating Reserve—Supplemental Reserve Service;
and (7) Generator Imbalance Service.
32 Promoting Wholesale Competition Through
Open Access Non-Discriminatory Transmission
Services by Public Utilities; Recovery of Stranded
Costs by Public Utilities and Transmitting Utilities,
Order No. 888, FERC Stats. & Regs. ¶ 31,036 (1996),
order on reh’g, Order No. 888–A, FERC Stats. &
Regs. ¶ 31,048, order on reh’g, Order No. 888–B, 81
FERC ¶ 61,248 (1997), order on reh’g, Order No.
888–C, 82 FERC ¶ 61,046 (1998), aff’d in relevant
part sub nom. Transmission Access Policy Study
Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d
sub nom. New York v. FERC, 535 U.S. 1 (2002).
33 Preventing Undue Discrimination and
Preference in Transmission Service, Order No. 890,
FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order
No. 890–A, FERC Stats. & Regs. ¶ 31,261 (2007),
order on reh’g, Order No. 890–B, 123 FERC ¶ 61,299
(2008), order on reh’g, Order No. 890–C, 126 FERC
¶ 61,228, order on clarification, Order No. 890–D,
129 FERC ¶ 61,126 (2009).
34 Section 215(a)(1) of the Federal Power Act
(FPA), 16 U.S.C. 824o(a)(1) (2012) defines ‘‘BulkPower System’’ as those ‘‘facilities and control
systems necessary for operating an interconnected
electric energy transmission network (or any
portion thereof) [and] electric energy from
generating facilities needed to maintain
transmission system reliability.’’ The term does not
include facilities used in the local distribution of
electric energy. See also Mandatory Reliability
Standards for the Bulk-Power System, Order No.
693, FERC Stats. & Regs. ¶ 31,242 at P 76, order on
reh’g, Order No. 693–A, 120 FERC ¶ 61,053 (2007).
35 Essential Reliability Services Task Force
Measures Report at vi.
36 NERC Frequency Response Initiative Report at
92.
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a disturbance.37 Additionally, in
February 2015, NERC issued an Industry
Advisory that determined that a
significant portion of generators within
the Eastern Interconnection use
deadbands or governor control settings
that either inhibit or prevent the
provision of primary frequency
response.38 Moreover, as noted in the
NOI, NERC observed in 2015 that in
many conventional steam plants,
deadband settings exceed ±0.036 Hz,
resulting in primary frequency response
that is not sustained, and that the vast
majority of the gas turbine fleet is not
frequency responsive.39 In response to
these issues and other concerns, NERC’s
Operating Committee approved a
voluntary Primary Frequency Control
Guideline that contains recommended
settings for generator governors and
other plant control systems, and
encourages generators within the three
U.S. Interconnections to provide
sustained and effective primary
frequency response.40 NERC’s Guideline
recommends maximum 5 percent droop
and ±0.036 Hz deadband settings for
most generating facilities.41
D. Initiatives by Individual
Transmission Providers
17. While the pro forma LGIA and pro
forma SGIA do not provide specific
requirements related to frequency
response, some public utility
transmission providers have included
provisions related to primary frequency
response in their LGIA, SGIA, OATTs,
and/or business practice manuals.
18. For example, ISO New England
Inc. (ISO–NE) and New York
Independent System Operator, Inc.
(NYISO) have adopted provisions to
their LGIAs that establish more specific
requirements for governor operation.42
37 NERC Frequency Response Initiative Report at
96–97.
38 NERC Generator Governor Frequency Response
Industry Advisory (Feb. 2015), https://
www.nerc.com/pa/rrm/bpsa/Alerts%20DL/2015
%20Alerts/NERC%20Alert%20A-2015-02-05-01
%20Generator%20Governor%20Frequency
%20Response.pdf.
39 NOI, 154 FERC ¶ 61,117 at P 50 (citing to NERC
2015 Frequency Response Webinar at 1).
40 See NERC Primary Frequency Control
Guideline Final Draft (Dec. 2015), https://
www.nerc.com/comm/OC/Reliability%20Guideline
%20DL/Primary_Frequency_Control_final.pdf
(NERC Primary Frequency Control Guideline). See
also NERC Operating Committee Meeting Minutes
(Jan. 2016), https://www.nerc.com/comm/OC/
AgendasHighlightsMinutes/Operating
%20Committee%20Minutes%20-%20Dec%2015-16
%202015-Final.pdf.
41 See NERC Primary Frequency Control
Guideline at 7–9.
42 See ISO–NE, Transmission, Markets and
Services Tariff, Schedule 22 Large Generator
Interconnection Procedures (9.0.0), Appendix 6,
9.6.2.2; NYISO, NYISO Tariffs, NYISO OATT, 30.14
OATT Att. X Appendices (8.0.0), Appendix 6, 9.5.4.
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85179
In particular, ISO–NE requires each
generator within its region with a
capability of 10 MW or more, including
VERs, to operate with a functioning
governor with specified droop and
deadband settings, i.e., maximum 5
percent droop and ±0.036 Hz deadband,
and to also ensure that the provision of
primary frequency response is not
inhibited by the effects of outer-loop
controls.43
19. PJM Interconnection, L.L.C. (PJM)
has implemented governor droop and
deadband requirements, i.e., maximum
5 percent droop and ±0.036 Hz
deadband, for all generating facilities
excluding nuclear facilities with a gross
plant/facility aggregate nameplate rating
greater than 75 MVA.44 PJM also
recently added new interconnection
requirements requiring new nonsynchronous generators to interconnect
with ‘‘enhanced inverters’’ that have
various capabilities including, among
other things, the ability to provide
primary frequency response.45
20. Midcontinent Independent System
Operator, Inc. (MISO) requires governor
operation as a condition for providing
regulating reserve but does not require
specific settings.46 Also, the
Commission recently accepted tariff
provisions proposed by the California
Independent System Operator
Corporation (CAISO) to require governor
operation, specified droop and
deadband settings, i.e., maximum 5
percent droop and ±0.036 Hz deadband,
and provisions for sustained primary
frequency response for its participating
generators that have traditional governor
controls.47
E. Notice of Inquiry
1. Summary
21. On February 18, 2016, the
Commission issued the NOI to explore
issues regarding essential reliability
43 See ISO–NE’s Operating Procedure No. 14 I
(Governor Control), https://www.iso-ne.com/rules_
proceds/operating/isone/op14/op14_rto_final.pdf.
44 PJM’s pro forma interconnection agreements
obligate interconnection customers within its region
to abide by all PJM rules and procedures, including
rules set forth in PJM’s Manuals (See PJM Tariff,
Attachment O 8.0). See also PJM Manual 14D 7.1.1
(Generator Real-Power Control), https://
www.pjm.com/∼/media/documents/manuals/
m14d.ashx.
45 PJM Interconnection, L.L.C., 151 FERC ¶
61,097, at n.58 (2015).
46 See MISO, FERC Electric Tariff, Module C,
Energy and Operating Reserve Markets 39.2.1B
(34.0.0) (‘‘All Regulation Qualified Resources in the
Day-Ahead Energy and Operating Reserve Market
must be capable of automatically responding to and
alleviating frequency deviations through a speed
governor or similar device in accordance with the
Applicable Reliability Standards.’’).
47 CAISO, 156 FERC ¶ 61,182, at PP 10–12 and
17 (2016).
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services and the evolving Bulk-Power
System.48 In particular, the Commission
asked a broad range of questions on the
need for reform of its rules and
regulations regarding the provision of
and compensation for primary
frequency response. The Commission
explained that there is a significant risk
that, as conventional synchronous
generating facilities retire or are
displaced by increased numbers of VERs
that do not typically contribute to
system inertia or have primary
frequency response capabilities, the net
amount of frequency responsive
generation online will be reduced.49 The
Commission also explained that these
developments and their potential
impacts could challenge system
operators in maintaining reliability.50
Further, the Commission explained that
NERC Reliability Standard BAL–003–
1.1 and the pro forma LGIA and pro
forma SGIA do not specifically address
a generator’s ability to provide
frequency response.51 The Commission
noted, however, that while in previous
years many non-synchronous generating
facilities were not designed with
primary frequency response capabilities,
the technology now exists for new nonsynchronous generating facilities to
install primary frequency response
capability.52
22. Accordingly, the Commission
requested comments on three main sets
of issues. First, the Commission sought
comment on whether amendments to
the pro forma LGIA and pro forma SGIA
are warranted to require all new
generating facilities, both synchronous
and non-synchronous, to have primary
frequency response capabilities as a
precondition of interconnection.53
Second, the Commission sought
comment on the performance of existing
generating facilities and whether
primary frequency response
requirements for these facilities are
warranted.54 Finally, the Commission
sought comment on compensation for
primary frequency response.55
2. Comments on Modifying the Pro
Forma LGIA and Pro Forma SGIA
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23. The Commission received a robust
response from industry, with 47 entities
collectively submitting nearly 700 pages
of comments that provided responses to
some or all of the questions posed by
48 NOI,
154 FERC ¶ 61,117.
P 12.
50 Id. P 14.
51 Id. P 41.
52 Id. P 43.
53 Id. PP 2 and 44–45.
54 Id. PP 2, 46, and 52.
55 Id. PP 2, 53–54.
49 Id.
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the NOI.56 Relevant to the proposed
revisions considered in this NOPR, the
Commission received numerous
comments on whether the pro forma
LGIA and pro forma SGIA should be
revised to include requirements for all
newly interconnecting generating
facilities, whether synchronous or nonsynchronous, to install primary
frequency response capability.57
a. Comments in Support of Modifying
the pro forma LGIA and pro forma SGIA
24. Most commenters support, or are
not opposed to, revising the pro forma
LGIA and SGIA to impose primary
frequency response capability
requirements on all new generating
facilities as suggested in the NOI.58
Several commenters indicate that the
nation’s changing resource mix could
create reliability concerns related to the
provision of primary frequency
response. For example, PJM Utilities
Coalition states that while newer
generating facilities are not installing
frequency response capability, the
existing generating facilities that do
provide this essential reliability service
have more limited capability, due to the
cost of operation and planned
retirements, placing the grid at further
risk.59 Peak Reliability, the reliability
coordinator for the Western
Interconnection, states that as baseload
generation retires, the number of
generators providing primary frequency
response is reduced and may present
reliability challenges for system
operators, as fewer options are available
to reduce frequency deviations
following an unexpected loss of
generation or load.60 CAISO asserts that
due to the increased proportion of
renewable generating facilities operating
in CAISO’s balancing authority area,
there may not be sufficient frequency
responsive capacity online when the
system has high renewable output and
low load levels.61 Bonneville states that
56 The Appendix lists the entities that submitted
comments and the shortened names that are used
throughout this NOPR.
57 NOI, 154 FERC ¶ 61,117 at P 45.
58 APPA, et al. Comments at 6; Bonneville
Comments at 6; CAISO Comments at 2; California
Cities Comments at 2; ELCON Comments at 5; EEI
Comments at 12; EPSA, et al. Comments at 8;
Howard F. Illian Comments at 43; Idaho Power
Comments at 1; IEEE–PES Comments at 1; Indicated
ISOs/RTOs Comments at 3; ITC, et al. Comments at
1; MISO Comments at 4; MISO TOs Comments at
6; NARUC Comments at 3; NERC Comments at 17;
North American Generator Forum Comments at 2;
Peak Reliability Comments at 4; PG&E Comments at
2; SoCal Edison Comments at 4; Southern Company
Comments at 2; Tri-State Generation Comments at
3; WIRAB Comments at 3.
59 PJM Utilities Coalition Comments at 3.
60 Peak Reliability Comments at 4.
61 CAISO Comments at 2.
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the trend of declining frequency
response capability will continue with a
changing resource mix, unless
provisions are put in place to assure that
adequate inertial and primary frequency
response capability are available in the
future.62 NERC states that the rapidly
changing resource mix may reduce the
level of available frequency capability.63
25. Numerous commenters assert that
they recognize the benefits of revising
the pro forma LGIA and pro forma SGIA
to require primary frequency response
capabilities for new generators. NERC,
for example, asserts that new primary
frequency response requirements for
generators will improve operator
flexibility for system restoration and
island capability and help balancing
authorities meet their frequency
response obligations.64 NERC also
asserts that revisions to the pro forma
LGIA and pro forma SGIA would result
in measurable, clear requirements
applicable to all new generating
facilities in a fair and equitable
manner.65 NERC points out, however,
that primary frequency response
capability, by itself, would not require
a resource to respond if called upon to
help a balancing authority meet its
frequency response obligation, and that,
as a result, it is important to have
mechanisms to ensure that sufficient
frequency response capability is not
only available but ready to respond at
all times.66 CASIO, Indicated ISOs/
RTOs, MISO, and a number of trade
associations also support modifications
to the pro forma LGIA and pro forma
SGIA for new generating facilities to
install primary frequency response
capability.67 PJM Utilities Coalition
states that, with all new generating
facilities (both synchronous and nonsynchronous) being fully capable of
providing primary frequency response,
requiring this capability will ensure that
system operators have the ability to
reliably operate the grid of the future.68
Peak Reliability states that it supports
modifications to the pro forma LGIA
and pro forma SGIA and that requiring
generating facilities to install or provide
frequency response in the initial stages
of the interconnection process will
ensure that the grid is able to maintain
62 Bonneville
63 NERC
Comments at 2.
Comments at 17.
64 Id.
65 Id.
66 Id.
at 18.
et al. Comments at 2; CAISO Comments
at 2; EEI Comments at 3; EPSA, et al. Comments at
8; Indicated ISOs/RTOs Comments at 3; MISO
Comments at 4; North American Generator Forum
Comments at 2.
68 PJM Utilities Coalition Comments at 4–5.
67 APPA,
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this essential service even as the
resource mix changes.69
26. Other commenters also express
support for revising the pro forma LGIA
and pro forma SGIA. Bonneville points
out that selling primary frequency
response capability would not provide
sufficient incentive for new generating
facilities to invest in such capability,
and argues that the only way to ensure
that there is enough primary frequency
response capability is to require new
generators to install it.70 WIRAB advises
that while current studies do not
indicate that there is a shortage of
primary frequency response in the
Western Interconnection and that all
generators do not need to provide
primary frequency response all of the
time, the Commission should, however,
require that all new generator owners
install primary frequency response
capability because of the changing
resource mix in the Western
Interconnection and the associated
uncertainty regarding the future
provision of primary frequency
response.71
27. Several commenters that generally
support revising the pro forma LGIA
and pro forma SGIA also express certain
concerns. For example, Southern
Company expresses support for revising
the pro forma LGIA and pro forma
SGIA, but caveats its support by arguing
that new regulations for primary
frequency response should include an
‘‘opt-out’’ provision that would allow
balancing authorities that do not
anticipate frequency response shortfalls
to delay the implementation of the new
pro forma LGIA and pro forma SGIA
requirements until these needs are
actually anticipated in their regions in
order to avoid higher costs.72 EPSA, et
al. state that while they do not fully
oppose amending the pro forma LGIA
and pro forma SGIA, they recommend
that the Commission explore more
effective and cost efficient ways to
address the range of issues posed in the
NOI and consider a measured approach
before mandating governors for all
prospective interconnecting
generation.73
28. Some commenters that support
modifying the pro forma LGIA and pro
forma SGIA also assert that the costs of
implementing primary frequency
response capability for new generating
facilities are low.74 For example, APPA,
69 Peak
Reliability Comments at 4–5.
Comments at 21.
71 WIRAB Comments at 5–6.
72 Southern Company Comments at 2–3.
73 EPSA, et al. Comments at 8–9.
74 APPA, et al. Comments at 6; Bonneville
Comments at 8; California Cities Comments at 2;
70 Bonneville
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et al. state that the capability for
providing primary frequency response is
almost always installed in synchronous
generation, and that the inclusion of this
additional control for new nonsynchronous generating facilities would
likely add only nominal costs.75 EEI
asserts that all new generating facilities
coming online can be fully capable of
providing primary frequency response
and that the associated cost of installing
such capability during initial
manufacturing or construction of a new
VER is small when considering the
overall cost of the new generating
facility.76
29. In contrast to new generating
facilities, some entities, however,
explain that the costs of retrofitting
existing generating facilities with
primary frequency response capability
could be significant in some cases.77 For
example, WIRAB states that the high
cost of retrofitting existing generators to
install the necessary control equipment
supports limiting the requirement to
new generators and taking early action
now.78
30. In regards to nuclear generating
facilities, some commenters indicate
that nuclear plants have separate
licensing requirements under the
Nuclear Regulatory Commission and
should not be required to provide
primary frequency response. For
example, the Nuclear Energy Institute
asserts that while nearly all new
generating facilities should be able to
provide primary frequency response,
nuclear plants are not well-suited to
provide primary frequency response due
to restrictions by their operating
licenses issued by the Nuclear
Regulatory Commission.79 The Nuclear
Energy Institute also asserts that turbine
controls on most nuclear units are
designed to maintain the internal steam
pressure and are not intended to react
to changes in the grid.80 Similarly, the
MISO TOs assert that requiring nuclear
units to have primary frequency
response capability would be contrary
to Nuclear Regulatory Commission
licensing requirements, and could have
a detrimental effect on the safety of the
nuclear fleet.81
EEI Comments at 13; Indicated ISOs/RTOs
Comments at 5; MISO Comments at 4; SoCal Edison
Comments at 2.
75 APPA, et al. Comments at 6.
76 EEI Comments at 13.
77 APPA, et al. Comments at 6; Bonneville
Comments at 8; California Cities Comments at 8;
EEI Comments at 14; Idaho Power Comments at 4;
WIRAB Comments at 6.
78 WIRAB Comments at 6.
79 Nuclear Energy Institute Comments at 1 and 4.
80 Nuclear Energy Institute Comments at 4.
81 MISO TOs Comments at 7.
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85181
31. In the NOI, the Commission also
sought comment on whether it would be
appropriate to include recommended
governor settings contained within
NERC’s Primary Frequency Control
Guideline in the pro forma LGIA and
pro forma SGIA.82 Numerous
commenters express support for
including NERC’s recommended
governor control settings in the pro
forma LGIA and pro forma SGIA.83
Some commenters note that NERC’s
Guideline is consistent with existing
regulations or practices in certain
regions.84 Indicated ISOs/RTOs point
out that common primary frequency
response settings for generators in an
Interconnection will enhance reliability
by reducing maneuvering by individual
generators.85 MISO asserts that NERC’s
Guideline provides a sound baseline.86
NERC notes that its Guideline was
developed by technical committees with
expertise and judgment of the electric
industry, and accordingly, the Guideline
is the ‘‘most advanced set of nationwide best practices and information
currently available to support frequency
response capability.’’ 87
32. However, not all entities that
support modifying the pro forma LGIA
and pro forma SGIA endorse the
inclusion of NERC’s recommended
governor settings. For example, EEI
states that it does not support including
prescriptive performance requirements
for governor control settings or other
performance indicators in the pro forma
LGIA or pro forma SGIA due to the
physical, technical, or operational
limitations of new generating facilities
to provide primary frequency
response.88 Similarly, APPA, et al. state
that they do not support revising the pro
forma LGIA and pro forma SGIA to
include the recommended settings
contained within NERC’s Guideline at
this time.89 MISO TOs state that some
transmission owners in MISO believe
that NERC’s recommended governor
settings are appropriate for traditional
synchronous generating facilities, but
recommend additional consideration for
other generation technologies.90 On the
other hand, MISO TOs state that other
transmission owners in MISO request
82 NOI,
154 FERC ¶ 61,117 at P 45.
e.g., Bonneville Comments at 7; IEEE–PES
Comments at 1; Indicated ISOs/RTOs Comments at
4; California Cities Comments at 2; WIRAB
Comments at 7.
84 Indicated ISOs/RTOs Comments at 4; SoCal
Edison Comments at 4; Peak Reliability Comments
at 7; Manitoba Comments at 8.
85 Indicated ISOs/RTOs Comments at 5.
86 MISO Comments at 4.
87 NERC Comments at 12.
88 EEI Comments at 15–17.
89 APPA, et al. Comments at 8.
90 MISO TOs Comments at 8.
83 See
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flexibility and assert that specified
governor settings should not be ‘‘hardwired’’ or dictated in the pro forma
LGIA and pro forma SGIA.91
b. Comments Opposed To Modifying the
pro forma LGIA and pro forma SGIA
33. Other commenters contend that
the pro forma LGIA and pro forma SGIA
should not be modified to require
primary frequency response capability
from new generating facilities.92 Some
commenters argue that requiring all new
generating facilities to have primary
frequency response capability will
result in extra costs above those
necessary to ensure reliability.93 For
example, APS argues that a global
mandate to provide primary frequency
response or to require generating
facilities to be primary frequency
response capable would result in
significantly increased costs while
providing a disproportionately minor
impact on improving reliability.94
Powerex asserts that modifying the pro
forma LGIA and pro forma SGIA to
include minimum primary frequency
response requirements will increase the
cost of entry for new generators,
particularly VERs, which typically are
not designed with such capability.95
Several commenters note that there
would be a significant opportunity cost
for certain generating facilities to
reserve headroom for the provision of
primary frequency response.96
34. Some of the commenters that are
opposed to modifying the pro forma
LGIA and pro forma SGIA assert that
they prefer a market-based approach
instead of a requirement for new
generating facilities to install primary
frequency response capability.97 For
example, AWEA asserts that, initially,
the pro forma LGIA and pro forma SGIA
should not be revised to require new
91 MISO
TOs Comments at 8.
Companies Comments at 6; Apex
Comments at 6; APS Comments at 6; AWEA
Comments at 12; Chelan County Comments at 2;
ESA Comments at 2; Grid Storage Consulting
Comments at 2; Microgrids Resources Coalition
Comments at 3; NRECA Comments at 9; Powerex
Comments at 5; SDG&E Comments at 3; SolarCity
Comments at 1; TVA Comments at 2.
93 Apex Comments at 5–6; APS Comments at 6;
AWEA Comments at 12; Chelan County Comments
at 2; Powerex Comments at 5; Solar City Comments
at 1.
94 APS Comments at 6. It is unclear whether the
increased costs referenced by APS refer only to the
costs for the necessary equipment to provide
primary frequency response or the costs associated
with maintaining the headroom necessary to
provide primary frequency response.
95 Powerex Comments at 5.
96 Apex Comments at 7; Solar City Comments at
1; AWEA Comments at 6.
97 Apex Comments at 6; AWEA Comments at 12;
Chelan County Comments at 2; ESA Comments at
2; SDG&E Comments at 3.
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92 AES
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generating facilities to have primary
frequency response capability, and only
if market-based steps do not
satisfactorily address the need for
primary frequency response, then the
Commission could consider an
additional requirement for new
generating facilities to have such
capability as a final step.98
35. Other commenters oppose
mandatory requirements and prefer a
voluntary approach to improving
primary frequency response
performance.99 For example, TVA
asserts that if current voluntary actions
fail to show improvement in primary
frequency response, then the pro forma
LGIA and pro forma SGIA could be
revised to contain a general primary
frequency response requirement, similar
to reactive power, but that NERC should
be directed to establish governor
settings and performance requirements
through the NERC Standards
Development Process instead of the
Commission including such
requirements in the pro forma LGIA and
pro forma SGIA.100 Some commenters
assert that governor control details are
better left to individual balancing
authorities.101 For example, APS argues
that the Commission should allow
balancing authorities to determine the
type and magnitude of generating
facilities within its balancing authority
area that are frequency-response
enabled.102 APS also points out that any
need to install frequency response
capability or otherwise support
frequency response performance can
and should be evaluated and agreed
upon between a generating facility and
the transmission provider during the
interconnection study process.103
II. Discussion
A. Primary Frequency Response
Requirements
1. The Need for Reform
36. Pursuant to FPA section 206, the
Commission preliminarily finds that
conditions have changed since the
issuance of Order Nos. 2003 and 2006
and certain aspects of the pro forma
LGIA and pro forma SGIA may now be
unjust, unreasonable, unduly
discriminatory, or preferential.104
98 AWEA
Comments at 12.
Comments at 8; NRECA Comments at 6;
TVA Comments at 2.
100 TVA Comments at 2–3 and 5.
101 APS Comments at 8; AES Companies
Comments at 8.
102 APS Comments at 8.
103 Id. at 15.
104 The Commission routinely evaluates the
effectiveness of its regulations and policies in light
of changing industry conditions to determine if
99 APS
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Specifically, as discussed above, the
record indicates that while the
frequency response performance of the
Eastern and Western Interconnections is
currently adequate, the frequency
response performance of both
Interconnections has significantly
declined from historic values.105
Furthermore, the record shows that
there is an ongoing evolution of the
nation’s generation resource mix,
including significant retirements of
baseload generation and an increasing
proportion of VERs interconnecting to
the electric grid.106 Several commenters
point out that there is significant risk
that the rapidly changing resource mix
may reduce the level of available
frequency response capability online.107
This is in part because, as noted in the
NOI, VERs have not been consistently
designed with primary frequency
response capabilities.108 The record
suggests, however, that VER
manufacturers have made significant
technological advancements in recent
years to develop primary frequency
response capability for VERs.109 In
addition, NERC, in conjunction with
various industry stakeholders, has
developed more robust technical
guidance for the operation of governors
or equivalent controls.110 As a result of
the evolving resource mix and the
potential for adverse impacts on
primary frequency response, the
Commission is concerned that there
may be potential reliability impacts if it
does not undertake the reforms
proposed in this NOPR. Moreover, the
Commission is concerned that certain
aspects of the existing pro forma LGIA
and pro forma SGIA may no longer be
just and reasonable.
37. First, the current requirements for
governor controls in the pro forma LGIA
do not reflect advances in technology or
the latest recommended operating
practices. Specifically, current Article
9.6.2.1 states that ‘‘speed governors,’’ if
installed, must be operated in automatic
changes are necessary. See, e.g., Order No. 764,
FERC Stats. & Regs. ¶ 31,331.
105 See NERC 2015 Frequency Response Webinar
at 10, NERC Frequency Response Initiative Report
at 22, and LBNL 2010 Report at pp xiv–xv.
106 See, e.g., P 12, supra (describing recent and
ongoing changes in the nation’s generation mix).
107 See, e.g., Bonneville Comments at 2; CAISO
Comments at 2; NERC Comments at 17; Peak
Reliability Comments at 4; PJM Utilities Coalition
Comments at 3.
108 NOI, 154 FERC ¶ 61,117 at PP 42–43.
109 See, e.g., PJM Utilities Comments at 4–5; EEI
Comments at 13. See also PJM Interconnection,
L.L.C., Docket No. ER15–1193–000 (March 6, 2015)
Transmittal Letter at 11. See also NERC 2014 LTRA,
at 27 (Nov. 2014), https://www.nerc.com/pa/RAPA/
ra/Reliability%20Assessments%20DL/2014LTRA_
ERATTA.pdf.
110 See P 16, supra.
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mode. However, many of the new
generating facilities interconnecting to
the grid, such as wind and solar, do not
utilize traditional speed governors;
instead they utilize enhanced inverters
and other plant supervisory control
technology that can be designed to
include primary frequency response
capability.111 Therefore, due to
advancements in technology, the
Commission preliminarily finds that the
existing references to ‘‘speed governors’’
in Article 9.6.2.1 that apply only to
synchronous resources are outdated,
and therefore may no longer be just and
reasonable.
38. Second, since the issuance of
Order No. 2003 and the establishment of
the pro forma LGIA, NERC, in
conjunction with industry stakeholders,
has amassed a significant body of
knowledge in regards to the operation of
generator governors and plant control
systems. For example, as noted above,
NERC observed in 2012 that a number
of generators implemented deadband
settings that were so wide as to
effectively defeat the ability to provide
primary frequency response, and that
many generators provide frequency
response in the wrong direction during
a disturbance.112 Additionally, as noted
above, NERC observed in 2015 that in
many conventional steam plants,
deadband settings exceed a ±0.036 Hz
dead band, resulting in primary
frequency response that is not
sustained, and that the vast majority of
the gas turbine fleet is not frequency
responsive.113
39. The record here suggests that the
actual governor and plant control
system settings that are being
implemented by some generator owners
and/or operators may be defeating the
intent of Article 9.6.2.1 of the pro forma
LGIA. In response to these issues,
NERC, through the work of its various
task forces, subcommittees, and
initiatives, has developed a voluntary
Guideline that includes recommended
droop and deadband settings based on
significant investigation.114 However,
the pro forma LGIA does not currently
reflect these updated recommended
111 See Electric Power Research Institute,
Recommended Settings for Voltage and Frequency
Ride Through of Distributed Energy Resources (May
2015) at 27, https://www.epri.com/abstracts/Pages/
ProductAbstract.aspx?ProductId=
000000003002006203. See also National Renewable
Energy Labs (NREL), Advanced Grid-Friendly
Controls Demonstration Project for Utility-Scale PV
Power Plants, at 1–2 (Jan. 2016), https://
www.nrel.gov/docs/fy16osti/65368.pdf.
112 See P 16, supra.
113 Id.
114 See NERC Primary Frequency Control
Guideline.
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practices for governor and plant control
system settings of generating facilities.
40. Third, given the nation’s evolving
resource mix and the potential adverse
impacts on primary frequency response
as noted in the NOI and pointed out by
several commenters, the Commission
believes that changes to the pro forma
LGIA and pro forma SGIA may be
necessary to provide for the continued
reliable operation of the power system.
As noted above, the Task Force
concluded that all new generating
facilities should be required to be
capable of providing primary frequency
response.115 However, the pro forma
LGIA does not currently require large
generating facilities to install such
capability; rather, it only requires
governor operation in ‘‘automatic
mode’’ if a ‘‘speed governor’’ is
installed.116
41. In addition, the Commission is
concerned that the current pro forma
SGIA may be unduly discriminatory or
preferential because it does not establish
any specific requirements with respect
to the installation or operation of
governors or equivalent frequency
control equipment. In particular, the pro
forma SGIA does not have a similar
provision to Article 9.6.2.1 of the pro
forma LGIA. The Commission has
previously acted under FPA section 206
to remove inconsistencies between the
pro forma LGIA and pro forma SGIA
when there is no economic or technical
basis for treating large and small
generating facilities differently.117
Similarly, in this instance, the record
developed from the NOI appears to
suggest that small generating facilities
are capable of installing and enabling
governors at low cost in a manner
comparable to large generating
facilities.118 As discussed above, the
record indicates that there have been
significant advances in technology, as
well as the development of more robust
technical guidance for the operation of
governors or equivalent controls for
both large and small generating
115 See
P 15, supra.
9.6.2.1 of the pro forma LGIA.
117 See Requirements for Frequency and Voltage
Ride Through Capability of Small Generating
Facilities, Order No. 828, 81 FR 50,290 (Aug. 1,
2016), 156 FERC ¶ 61,062 (2016), (The Final Rule
revised the pro forma SGIA such that small
generating facilities have frequency and voltage ride
through requirements comparable to large
generating facilities).
118 IEEE–P1547 Working Group Comments at 1, 5,
and 7. Moreover, the Commission notes that other
commenters stated costs of installing primary
frequency response capability are generally low, but
did not differentiate between small and large
generating facilities. See, e.g., APPA, et al.
Comments at 6; California Cities Comments at 2;
EEI Comments at 13; Indicated ISOs/RTOs
Comments at 3–5; SoCal Edison Comments at 2.
116 Article
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85183
facilities.119 In particular, the IEEE–
P1547 Working Group noted that its
new IEEE–1547 standard for
interconnecting distributed generation
will likely include certain requirements
for providing primary frequency
response.120 Given these low-cost
technological advances, the Commission
does not anticipate that these additional
requirements added in the pro forma
SGIA will present a barrier to entry for
small generating facilities. And, given
the need for additional primary
frequency response capability and an
increasingly large market penetration of
small generating facilities, the
Commission believes that there is a
need to add these requirements to the
pro forma SGIA to help ensure adequate
primary frequency response capability.
42. Moreover, as noted above, a
number of commenters assert that costs
for new generating facilities to install
the capability of providing primary
frequency response are low, suggesting
that there is not a financial barrier to
small generating facilities installing the
capability to provide frequency
response.121 PJM’s recent changes to
require both small and large nonsynchronous generating facilities to use
enhanced inverters, which include
primary frequency response capability,
among other functions, further support
this notion.122
2. Commission Proposal
43. To remedy the potentially unjust,
unreasonable, and unduly
discriminatory or preferential practices
described above, the Commission
preliminarily finds that revisions to the
pro forma LGIA and pro forma SGIA are
appropriate. The Commission believes
that revising the pro forma LGIA and
pro forma SGIA to require all new
generating facilities to install, maintain,
and operate a functioning governor or
equivalent controls, consistent with the
proposed requirements described below,
will help to ensure adequate primary
frequency response capability as the
resource mix continues to evolve,
ensure fair and consistent treatment for
all types of generating facilities, help
balancing authorities meet their
frequency response obligations pursuant
to NERC Reliability Standard BAL–003–
1.1, and help improve reliability during
119 See
PP 13, 36, supra.
Working Group Comments at 1, 5,
120 IEEE–P1547
and 7.
121 See, e.g., APPA, et al. Comments at 2; EEI
Comments at 13; Indicated ISOs/RTOs Comments at
5; SoCal Edison Comments at 2.
122 PJM Interconnection, L.L.C., 151 FERC ¶
61,097 at P 28 (the Commission stated that it
‘‘find[s] that PJM’s proposal will not present a
barrier to non-synchronous resources.’’).
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system restoration and islanding
situations.123
44. In particular, the Commission
proposes to revise the pro forma LGIA
and pro forma SGIA to include the
following: (1) Requirements for new
large and small generating facilities,
both synchronous and nonsynchronous, to install, maintain, and
operate equipment capable of providing
primary frequency response as a
condition of interconnection; (2)
requirements for governor or equivalent
controls to be operated, at a minimum,
with maximum 5 percent droop and
±0.036 Hz deadband settings; (3)
requirements to ensure the timely and
sustained response to frequency
deviations, including provisions to
prevent plant-level (i.e., outer-loop)
control equipment from inhibiting
primary frequency response and
resulting in premature withdrawal; and
(4) a requirement for droop parameters
to be based on nameplate capability
with a linear operating range of 59 to 61
Hz. Additionally, as informed by NOI
commenters, the Commission believes
that it is not necessary to impose a
generic headroom requirement or
subject newly interconnecting nuclear
generating facilities to the new
requirements. The Commission does not
propose to mandate any separate
compensation related to the proposed
requirements. The Commission seeks
comment on the proposed reforms, as
discussed more fully below.
45. Specifically, the Commission
proposes to revise existing sections 9.6
and 9.6.2.1 of the pro forma LGIA and
to include proposed new sections 9.6.4,
9.6.4.1, 9.6.4.2, and 9.6.4.3. Similarly,
the Commission proposes to revise
existing section 1.8 of the pro forma
SGIA and add proposed new sections
1.8.4, 1.8.4.1, 1.8.4.1.1, 1.8.4.1.2, and
1.8.4.1.3.124
46. The Commission’s proposed
revisions to the pro forma LGIA and pro
forma SGIA would apply to new
generating facilities that execute or
request the unexecuted filing of
interconnection agreements on or after
the effective date of any Final Rule
issued in Docket No. RM16–6–000. The
Commission also proposes to apply the
requirements to any large or small
generating facility that has an executed
or has requested the filing of an
unexecuted LGIA or SGIA as of the
effective date of any Final Rule in
Docket No. RM16–6–000, but that takes
123 See NERC Comments at 17. See also NERC
Essential Reliability Services Task Force Measures
Framework Report at iv.
124 The specific proposed modifications and
additions to the pro forma LGIA and pro forma
SGIA are set forth at PP 52–53, below.
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any action that requires the submission
of a new interconnection request that
results in the filing of an executed or
unexecuted interconnection agreement
on or after the effective date of any Final
Rule in Docket No. RM16–6–000.
47. In particular, the proposed
revisions to the pro forma LGIA and pro
forma SGIA would require new large
and small generating facilities to install,
maintain, and operate a functioning
governor or equivalent controls, which
the Commission proposes to define as
the required hardware and/or software
that provides frequency responsive real
power control with the ability to sense
changes in system frequency and
autonomously adjust the generating
facility’s real power output in
accordance with the proposed
maximum droop and deadband
parameters and in the direction needed
to correct frequency deviations. The
Commission seeks comment on this
proposal.
48. The Commission also proposes to
require new large and small generating
facilities to install, maintain and operate
governor or equivalent controls with the
ability to operate with a maximum 5
percent droop and ±0.036 Hz deadband
parameter, consistent with NERC’s
recommended guidance. As noted
above, the Commission sought comment
in the NOI on whether NERC’s
recommended guidance for governor
settings related to droop and deadband
should be included in the pro forma
LGIA and pro forma SGIA, and
numerous commenters agreed stating
that NERC’s Guideline provides a sound
baseline.125 Therefore, the Commission
preliminarily finds that a maximum
droop setting of 5 percent and deadband
setting of ±0.036 Hz are appropriate to
include in the pro forma LGIA and pro
forma SGIA as interconnection
requirements for new generating
facilities. The Commission notes that
these proposed requirements are
minimum requirements; therefore, if a
new generating facility elects, in
coordination with its transmission
provider, to operate in a more
responsive mode by using lower droop
or tighter deadband settings, nothing in
these requirements would prohibit it
from doing so.126 The Commission seeks
comment on these proposed
125 See
e.g., Bonneville Comments at 7; California
Cities Comments at 2; IEEE–PES Comments at 2;
Indicated ISOs/RTOs Comments at 4; MISO
Comments at 4; WIRAB Comments at 7.
126 Moreover, the Commission proposes that
nothing in these requirements would prohibit the
implementation of asymmetrical droop settings (i.e.,
different droop settings for under-frequency and
over-frequency conditions), provided that each
segment has a droop value of no more than 5
percent.
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requirements for droop and deadband
settings.
49. The Commission also proposes to
prohibit all new large and small
generating facilities from taking any
action that would inhibit the provision
of primary frequency response, except
under certain conditions as discussed
below. The lack of coordination
between governor and plant-level
control systems can result in premature
withdrawal of primary frequency
response by allowing additional plant
control systems to reverse the action of
the governor to return the unit to
operating at a pre-selected target setpoint.127 NERC’s Guideline explains
that ‘‘in order to provide sustained
primary frequency response, it is
essential that the prime mover governor,
plant controls and remote plant controls
are coordinated.’’ 128 Accordingly, the
Commission proposes to require new
generating facilities that respond to
frequency deviations to not inhibit
primary frequency response, such as by
coordinating plant-level, outer-loop
control equipment with the governor or
equivalent controls, except under
certain operational constraints
including, but not limited to, ambient
temperature limitations, outages of
mechanical equipment, or regulatory
requirements. The Commission also
proposes to require new generating
facilities to respond to frequency
deviations without undue delay and to
sustain the response until at least
system frequency returns to a stable
value within the governor’s deadband
setting. The Commission believes this
proposed requirement for sustained
response is consistent with the current
requirements of PJM and ISO–NE as
well as similar OATT revisions recently
implemented by CAISO.129 The
Commission seeks comment on the
proposed requirements for sustained
response. In particular, the Commission
seeks comment on whether these
provisions will be sufficient to prevent
plant-level (i.e., outer-loop) controls
from inhibiting primary frequency
response.
50. Regarding droop settings, in its
comments to the NOI, MISO proposed
that a linear droop should be available
between 59 to 61 Hz.130 The
127 NERC Frequency Response Initiative Report at
31. See also NOI, 154 FERC ¶ 61,117 at P 49 (stating
that primary frequency response withdrawal ‘‘has
the potential to degrade the overall response of the
Interconnection and result in a frequency that
declines below the original nadir’’).
128 NERC Primary Frequency Control Guideline at
4.
129 See, e.g., ISO–NE Operating Procedure OP–14
and PJM Manual 14D. See also CAISO, 156 FERC
¶ 61,182 at PP 10–12 and 17.
130 MISO Comments at 4.
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Commission believes that this is
reasonable because it would allow for
new generating facilities that remain
connected during frequency deviations
to provide a proportional response
within this range of frequencies.
Accordingly, the Commission proposes
to require the droop parameter to be
based on the nameplate capability of the
unit and linear in operating range
between 59 to 61 Hz. The Commission
seeks comment on these proposed
requirements for droop settings.
51. Several NOI commenters
expressed concern about possible
generic headroom requirements 131 that
could result in significant opportunity
costs.132 The Commission clarifies that
nothing in these proposed reforms will
impose a generic headroom requirement
for new generating facilities or affect the
unit commitment and dispatch
decisions of balancing authorities.
Therefore, if a generating facility that is
subject to these proposed requirements
has been dispatched by its balancing
authority to a set-point at which there
is no available operating range to
increase or decrease its output in
response to frequency deviations, it
would not be in violation of the
proposed requirements in regards to
providing sustained response. The
Commission believes that the reliability
benefits from the proposed
modifications to the pro forma LGIA
and pro forma SGIA do not require
imposing additional costs that would
result from a generic headroom
requirement. The Commission also
agrees with NOI commenters regarding
the unique operating characteristics and
regulatory requirements of nuclear
generating facilities regulated by the
Nuclear Regulatory Commission, and
therefore proposes to exempt such
generating facilities from the proposed
reforms.133 The Commission seeks
comment on the proposal to not impose
a generic headroom requirement and to
not apply the new requirements to
nuclear generating facilities.
52. In light of the above discussion,
the Commission proposes to modify
sections 9.6 and 9.6.2.1 of the pro forma
LGIA and add new sections 9.6.4,
9.6.4.1, 9.6.4.2, and 9.6.4.3 as follows:
131 A generic headroom requirement would
require generating facilities to operate below
maximum output at all times to ensure sufficient
ability to increase their real power output in
response to under-frequency conditions.
132 See, e.g., Apex Comments at 7; Solar City
Comments at 1; AWEA Comments at 6.
133 See, e.g., Nuclear Energy Institute Comments
at 1, 4; MISO TOs Comments at 7.
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9.6 Reactive Power and Primary Frequency
Response
9.6.2.1 Voltage Regulators. Whenever the
Large Generating Facility is operated in
parallel with the Transmission System and
voltage regulators are capable of operation,
Interconnection Customer shall operate the
Large Generating Facility with its voltage
regulators in automatic operation. If the Large
Generating Facility’s voltage regulators are
not capable of such automatic operation,
Interconnection Customer shall immediately
notify Transmission Provider’s system
operator, or its designated representative, and
ensure that such Large Generating Facility’s
reactive power production or absorption
(measured in MVARs) are within the design
capability of the Large Generating Facility’s
generating unit(s) and steady state stability
limits. Interconnection Customer shall not
cause its Large Generating Facility to
disconnect automatically or instantaneously
from the Transmission System or trip any
generating unit comprising the Large
Generating Facility for an under or over
frequency condition unless the abnormal
frequency condition persists for a time period
beyond the limits set forth in ANSI/IEEE
Standard C37.106, or such other standard as
applied to other generators in the Control
Area on a comparable basis.
9.6.4 Primary Frequency Response.
Interconnection Customer shall ensure the
primary frequency response capability of its
Large Generating Facility by installing,
maintaining, and operating a functioning
governor or equivalent controls. The term
‘‘functioning governor or equivalent controls’’
as used herein shall mean the required
hardware and/or software that provides
frequency responsive real power control with
the ability to sense changes in system
frequency and autonomously adjust the Large
Generating Facility’s real power output in
accordance with the droop and deadband
parameters and in the direction needed to
correct frequency deviations. Interconnection
Customer is required to install a governor or
equivalent controls with the capability of
operating with a maximum 5 percent droop
and ±0.036 Hz deadband. The droop
characteristic shall be based on the
nameplate capacity of the Large Generating
Facility, and shall be linear in the range of
59 to 61 Hz. The deadband parameter shall
be the range of frequencies above and below
nominal (60 Hz) in which the governor or
equivalent controls is not expected to adjust
the Large Generating Facility’s real power
output in response to frequency deviations.
Interconnection Customer shall notify
Transmission Provider that the primary
frequency response capability of the Large
Generating Facility has been tested and
confirmed during commissioning. Once
Interconnection Customer has synchronized
the Large Generating Facility with the
Transmission System, Interconnection
Customer shall operate the Large Generating
Facility consistent with provisions specified
in Sections 9.6.4.1 and 9.6.4.2 of this
Agreement. The primary frequency response
requirements contained herein shall apply to
both synchronous and non-synchronous
Large Generating Facilities. Nothing in
Sections 9.6.4, 9.6.4.1 and 9.6.4.2 shall
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85185
require the Large Generating Facility to
operate above its minimum operating limit or
below its maximum operating limit, or
otherwise alter its dispatch to have headroom
to provide primary frequency response.
9.6.4.1 Governor or Equivalent Controls.
Whenever the Large Generating Facility is
operated in parallel with the Transmission
System, Interconnection Customer shall
operate the Large Generating Facility with its
governor or equivalent controls in service and
responsive to frequency. Interconnection
Customer shall, in coordination with
Transmission Provider, set the deadband
parameter to a maximum of ±0.036 Hz and
set the droop parameter to a maximum of 5
percent. Interconnection Customer shall be
required to provide the status and settings of
the governor or equivalent controls to
Transmission Provider upon request. If
Interconnection Customer needs to operate
the Large Generating Facility with its
governor or equivalent controls not in
service, Interconnection Customer shall
immediately notify Transmission Provider’s
system operator, or its designated
representative. Interconnection Customer
shall make Reasonable Efforts to return its
governor or equivalent controls into service
as soon as practicable.
9.6.4.2 Sustained Response.
Interconnection Customer shall ensure that
the Large Generating Facility’s real power
response to sustained frequency deviations
outside of the deadband setting is provided
without undue delay, and ensure that the
response is not inhibited, except under
certain operational constraints including, but
not limited to, ambient temperature
limitations, outages of mechanical
equipment, or regulatory requirements. The
Large Generating Facility shall sustain the
real power response at least until system
frequency returns to a stable value within the
deadband setting of the governor or
equivalent controls.
9.6.4.3 Exemptions. Large Generating
Facilities that are regulated by the United
States Nuclear Regulatory Commission shall
be exempt from Sections 9.6.4, 9.6.4.1, and
9.6.4.2 of this Agreement.
53. Similarly, the Commission
proposes to modify section 1.8 of the
pro forma SGIA and add new sections
1.8.4, 1.8.4.1, 1.8.4.2 and 1.8.4.3 as
follows:
1.8 Reactive Power and Primary Frequency
Response
1.8.4 Primary Frequency Response.
Interconnection Customer shall ensure the
primary frequency response capability of its
Small Generating Facility by installing,
maintaining, and operating a functioning
governor or equivalent controls. The term
‘‘functioning governor or equivalent controls’’
as used herein shall mean the required
hardware and/or software that provides
frequency responsive real power control with
the ability to sense changes in system
frequency and autonomously adjust the
Small Generating Facility’s real power output
in accordance with the droop and deadband
parameters and in the direction needed to
correct frequency deviations. Interconnection
Customer is required to install a governor or
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equivalent controls with the capability of
operating with a maximum 5 percent droop
and ±0.036 Hz deadband. The droop
characteristic shall be based on the
nameplate capacity of the Small Generating
Facility, and shall be linear in the range of
59 to 61 Hz. The deadband parameter shall
be the range of frequencies above and below
nominal (60 Hz) in which the governor or
equivalent controls is not expected to adjust
the Small Generating Facility’s real power
output in response to frequency deviations.
Interconnection Customer shall notify
Transmission Provider that the primary
frequency response capability of the Small
Generating Facility has been tested and
confirmed during commissioning. Once
Interconnection Customer has synchronized
the Small Generating Facility with the
Transmission System, Interconnection
Customer shall operate the Small Generating
Facility consistent with the provisions
specified in Sections 1.8.4.1 and 1.8.4.2 of
this Agreement. The primary frequency
response requirements contained herein shall
apply to both synchronous and nonsynchronous Small Generating Facilities.
Nothing in Sections 1.8.4, 1.8.4.1 and 1.8.4.2
shall require the Small Generating Facility to
operate above its minimum operating limit,
below its maximum operating limit, or
otherwise alter its dispatch to have headroom
to provide primary frequency response.
1.8.4.1 Governor or Equivalent Controls.
Whenever the Small Generating Facility is
operated in parallel with the Transmission
System, Interconnection Customer shall
operate the Small Generating Facility with its
governor or equivalent controls in service and
responsive to frequency. Interconnection
Customer shall, in coordination with
Transmission Provider, set the deadband
parameter to a maximum of ±0.036 Hz and
set the droop parameter to a maximum of 5
percent. Interconnection Customer shall be
required to provide the status and settings of
the governor or equivalent controls to
Transmission Provider upon request. If
Interconnection Customer needs to operate
the Small Generating facility with its
governor or equivalent controls not in
service, Interconnection Customer shall
immediately notify Transmission Provider’s
system operator, or its designated
representative. Interconnection Customer
shall make Reasonable Efforts to return its
governor or equivalent controls into service
as soon as practicable.
1.8.4.2 Sustained Response.
Interconnection Customer shall ensure that
the Small Generating Facility’s real power
response to sustained frequency deviations
outside of the deadband setting is provided
without undue delay, and ensure that the
response is not inhibited, except under
certain operational constraints including, but
not limited to, ambient temperature
limitations, outages of mechanical
equipment, or regulatory requirements. The
Small Generating Facility shall sustain the
real power response at least until system
frequency returns to a stable value within the
deadband setting of the governor or
equivalent controls.
1.8.4.3 Exemptions. Small Generating
Facilities that are regulated by the United
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States Nuclear Regulatory Commission shall
be exempt from Sections 1.8.4, 1.8.4.1,
1.8.4.2 of this Agreement.
54. The Commission proposes to
apply the primary frequency response
requirements to any new large or small
generating facility that executes or
requests the unexecuted filing of a LGIA
or SGIA on or after the effective date of
any Final Rule issued in this
proceeding. In addition, the
Commission proposes to apply the
requirements to any large or small
generating facility that has an executed
or has requested the filing of an
unexecuted LGIA or SGIA as of the
effective date of any Final Rule in
Docket No. RM16–6–000, but that takes
any action that requires the submission
of a new interconnection request that
results in the filing of an executed or
unexecuted interconnection agreement
on or after the effective date of any Final
Rule in Docket No. RM16–6–000. The
Commission seeks comment on the
proposed effective date including
whether applying these requirements to
existing generating facilities that take
any action that requires the submission
of a new interconnection request that
results in the filing of an executed or
unexecuted interconnection agreement
on or after the effective date of any Final
Rule in Docket No. RM16–6–000 would
be unduly burdensome.
55. The Commission does not propose
in this NOPR to require that the
interconnection customer receive any
compensation for these proposed
requirements. The Commission has
previously accepted changes to
transmission provider tariffs that
similarly required interconnection
customers to install primary frequency
response capability or that established
specified governor settings, without
requiring any accompanying
compensation.134 While the
Commission has not required
compensation for similar requirements
in the past, it clarifies that nothing in
this NOPR is meant to prohibit a public
utility from filing a proposal for primary
frequency response compensation under
FPA section 205, if it so chooses.135
B. Request for Comment
56. The Commission seeks comment
on the proposed: (1) Requirements for
new large and small generating facilities
to install, maintain, and operate a
governor or equivalent controls; (2)
requirements for droop and deadband
134 PJM Interconnection, L.L.C., 151 FERC ¶
61,097, at n.58 (2015); CAISO, 156 FERC ¶ 61,182,
at PP 10–12 and 17 (2016); New England Power
Pool, 109 FERC ¶ 61,155 (2004), order on reh’g, 110
FERC ¶ 61,335 (2005).
135 16 U.S.C. 824d (2012).
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settings of 5 percent and ±0.036 Hz,
respectively; (3) requirements for timely
and sustained response; (4) requirement
for droop parameters to be based on
nameplate capability with a linear
operating range of 59 to 61 Hz; (5)
exemptions for new nuclear units; and
(6) effective dates as discussed above.
The Commission also seeks comment on
its proposal to not impose a generic
headroom requirement or mandate
compensation related to the proposed
reforms.
57. In the NOI, the Commission also
sought comment on the performance of
existing resources and whether primary
frequency response requirements for
these resources are warranted.136 At this
time, the Commission proposes only to
adopt the reforms included in this
NOPR regarding newly interconnecting
large and small generating facilities.
However, the Commission seeks
comment regarding whether the reforms
proposed in this NOPR are sufficient to
ensure adequate levels of primary
frequency response, or whether
additional reforms are needed. In
particular, the Commission seeks
comment on whether additional
primary frequency response
performance or capability requirements
for existing resources are needed, and if
so, whether the Commission should
impose those requirements by: (1)
Directing the development or
modification of a reliability standard
pursuant to section 215(d)(5) of the
FPA; or (2) acting pursuant to section
206 of the FPA to require changes to the
pro forma OATT.
C. Proposed Compliance Procedures
58. The Commission proposes to
require all public utility transmission
providers to adopt the requirements of
any Final Rule in Docket No. RM16–6–
000 as revisions to the LGIA and SGIA
in their OATTs within 60 days after the
publication of the Final Rule in the
Federal Register.
59. Some public utility transmission
providers may have provisions in their
existing LGIAs and SGIAs that the
Commission has found to be consistent
with or superior to the pro forma LGIA
and pro forma SGIA. Where these
provisions would be modified by the
Final Rule, public utility transmission
providers must either comply with the
Final Rule or demonstrate that these
previously-approved variations
continue to be consistent with or
superior to the pro forma LGIA and pro
forma SGIA as modified by the Final
Rule. The Commission also proposes to
permit appropriate entities to seek
136 NOI,
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‘‘independent entity variations’’ from
the proposed revisions to the pro forma
LGIA and pro forma SGIA.137
60. The Commission would assess
whether each compliance filing satisfies
the proposed requirements stated above
and issue additional orders as necessary
to ensure that each public utility
transmission provider meets the
requirements of the subsequent Final
Rule.
61. The Commission also proposes
that transmission providers that are not
public utilities would have to adopt the
requirements of this proposal and
subsequent Final Rule as a condition of
maintaining the status of their safe
harbor tariff or otherwise satisfying the
reciprocity requirement of Order No.
888.138
III. Information Collection Statement
62. The Paperwork Reduction Act
(PRA) 139 requires each federal agency to
seek and obtain Office of Management
and Budget (OMB) approval before
undertaking a collection of information
directed to ten or more persons, or
contained in a rule of general
applicability. OMB’s regulations require
the approval of certain information
collection requirements imposed by
agency rules.140 Upon approval of a
collection of information, OMB will
assign an OMB control number and an
expiration date. Respondents subject to
the filing requirements of this proposal
will not be penalized for failing to
respond to this collection of information
unless the collection of information
displays a valid OMB control number.
Transmission providers are subject to
the proposed revisions to the pro forma
LGIA and SGIA.
63. In this NOPR, the Commission
proposes to amend its pro forma LGIA
and pro forma SGIA in accordance with
section 35.28(f)(1) of its regulations.141
The proposed revisions to the pro forma
LGIA and pro forma SGIA would
require new large and small generating
facilities to install, maintain, and
operate a functioning governor or
equivalent controls which the
Commission proposes to define as the
required hardware and/or software that
provides frequency responsive real
power control with the ability to sense
changes in system frequency and
autonomously adjust the generating
facility’s real power output in
accordance with the proposed
maximum droop and dead band
parameters and in the direction needed
to correct frequency deviations. The
NOPR proposes to require each public
utility transmission provider to amend
its pro forma LGIA and pro forma SGIA
to require that all newly interconnecting
large and small generating facilities, as
well as all existing large and small
generating facilities that take any action
85187
that requires the submission of a new
interconnection request that results in
the filing of an executed or unexecuted
interconnection agreement, to adhere to
the proposed requirements, on or after
the effective date of any Final Rule
issued in this proceeding.
64. The reforms in this NOPR would
require filings of pro forma LGIAs and
pro forma SGIAs with the Commission.
The Commission anticipates the
proposed reforms, once implemented,
would not significantly change
currently existing burdens on an
ongoing basis. With regard to those
public utility transmission providers
that believe that they already comply
with the proposed reforms in this
NOPR, they could demonstrate their
compliance in the filing required 60
days after publication of the Final Rule
in the Federal Register. The
Commission will submit the proposed
reporting requirements to OMB for its
review and approval under section
3507(d) of the Paperwork Reduction
Act.142 The Commission will use FERC–
516B as a temporary ‘‘placeholder’’
information collection number.143
Burden Estimate: 144 The Commission
believes that the burden estimates below
are representative of the average burden
on respondents. The estimated burden
and cost for the requirements contained
in this NOPR follow.145
FERC 516B, IN NOPR IN RM16–6
Number of
respondents 146
Annual
number of
responses per
respondent
Total number
of responses
Average burden
(hours) & cost ($)
per response
Total annual burden
hours & total annual cost
($)
(1)
(2)
(1) * (2) = (3)
(4)
(3) * (4) = (5)
LGIA & SGIA changes/revisions ..................
74
1
74
10 hours; $745.00
740 hours; $55,130.00.
Total ......................................................
........................
........................
74
...............................
740 hours; $55,130.00.
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There are no maintenance cost,
installation cost or any additional cost
or requirements after year 1.
Title: FERC–516B, Electric Rate
Schedules and Tariff Filings.
Action: Revision of currently
approved collection of information.
OMB Control No.: 1902–0286.
Respondents for this Rulemaking:
Businesses or other for profit and/or
not-for-profit institutions.
Frequency of Information: One-time
during year 1.
Necessity of Information: The
Commission proposes to revise its
regulations to require all newly
interconnecting large and small
137 See, e.g., Order No. 2003, FERC Stats. & Regs.
¶ 31,146 at P 827.
138 Order No. 888, FERC Stats. & Regs. ¶ 31,036
at 31,760–63.
139 44 U.S.C. 3501–3520 (2012).
140 5 CFR 1320.11 (2016).
141 18 CFR 35.28(f)(1) (2016).
142 44 U.S.C. 3507(d) (2012).
143 The reporting requirements in this NOPR
would normally be included under FERC–516
(OMB Control No. 1902–0096). However, FERC–516
is pending review at OMB in an unrelated action.
Because only one item per OMB Control No. can
be pending OMB review at a time, the Commission
is temporarily using the information collection
number FERC–516B (OMB Control No. 1902–0286)
to ensure timely submittal of this NOPR to OMB.
144 Burden means the total time, effort, or
financial resources expended by persons to
generate, maintain, retain, disclose or provide
information to or for a Federal agency, including:
The time, effort, and financial resources necessary
to comply with a collection of information that
would be incurred by persons in the normal course
of their activities (e.g., in compiling and
maintaining business records) will be excluded
from the ‘‘burden’’ if the agency demonstrates that
the reporting, recordkeeping, or disclosure activities
needed to comply are usual and customary.
145 For this information collection, the
Commission staff estimates that industry is
similarly situated in terms of hourly cost (wages
plus benefits). Based on the Commission’s average
cost (wages plus benefits) for 2016, the Commission
is using $74.50/hour.
146 The NERC Compliance Registry lists 80
entities that administer a transmission tariff and
provide transmission service. The Commission
identifies only 74 as being subject to the proposed
requirements because 6 are Canadian entities and
are not under the Commission’s jurisdiction.
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Federal Register / Vol. 81, No. 227 / Friday, November 25, 2016 / Proposed Rules
generating facilities, both synchronous
and non-synchronous, to install,
maintain, and operate equipment
capable of providing primary frequency
response as a condition of
interconnection. To implement these
requirements, the Commission proposes
to revise the pro forma LGIA and the
pro forma SGIA.
Internal Review: The Commission has
reviewed the proposed changes and has
determined that the changes are
necessary. These requirements conform
to the Commission’s need for efficient
information collection, communication,
and management within the energy
industry. The Commission has assured
itself, by means of internal review, that
there is specific, objective support for
the burden estimates associated with the
information collection requirements.
65. Interested persons may obtain
information on the reporting
requirements by contacting the
following: Federal Energy Regulatory
Commission, 888 First Street NE.,
Washington, DC 20426 [Attention: Ellen
Brown, Office of the Executive Director],
email: DataClearance@ferc.gov, Phone:
(202) 502–8663, fax: (202) 273–0873.
66. Comments on the collection of
information and the associated burden
estimate in the proposed rule should be
sent to the Commission in this docket
and may also be sent to the Office of
Information and Regulatory Affairs,
Office of Management and Budget, 725
17th Street NW., Washington, DC 20503
[Attention: Desk Officer for the Federal
Energy Regulatory Commission], at the
following email address: oira_
submission@omb.eop.gov. Please refer
to OMB Control No. 1902–0286 in your
submission.
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IV. Environmental Analysis
67. The Commission is required to
prepare an Environmental Assessment
or an Environmental Impact Statement
for any action that may have a
significant adverse effect on the human
environment.147 The Commission
concludes that neither an
Environmental Assessment or an
Environmental Impact Statement is
required for proposed revisions under
section 380.4(a)(15) of the Commission’s
regulations, which provides a
categorical exemption for approval of
actions under sections 205 and 206 of
the FPA relating to the filing of
schedules containing all rates and
charges for the transmission or sale of
electric energy subject to the
147 Order No. 486, Regulations Implementing the
National Environmental Policy Act, 52 FR 47897
(Dec. 17, 1987), FERC Stats. & Regs. Preambles
1986–1990 ¶ 30,783 (1987).
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Commission’s jurisdiction, plus the
classification, practices, contracts and
regulations that affect rates, charges,
classifications, and services.148 The
revisions proposed in this NOPR update
and clarify the application of the
Commission’s standard interconnection
requirements to synchronous and nonsynchronous generators. Therefore, this
NOPR falls within the categorical
exemptions provided in the
Commission’s regulations, and therefore
neither an Environmental Assessment
nor an Environmental Impact Statement
is required.
V. Regulatory Flexibility Act
68. The Regulatory Flexibility Act of
1980 (RFA) 149 generally requires a
description and analysis of proposed
rules that will have significant
economic impact on a substantial
number of small entities. The RFA does
not mandate any particular outcome in
a rulemaking. It only requires
consideration of alternatives that are
less burdensome to small entities and an
agency explanation of why alternatives
were rejected.
69. The Small Business
Administration (SBA) revised its size
standards (effective January 22, 2014)
for electric utilities from a standard
based on megawatt hours to a standard
based on the number of employees,
including affiliates. Under SBA’s
standards, some transmission owners
will fall under the following category
and associated size threshold: Electric
bulk power transmission and control, at
500 employees.150
70. The Commission estimates that
the total number of transmission
providers, both public and non-public,
affected by this NOPR is 74.151 Of these,
the Commission estimates that
approximately 27.5 percent are small
entities. The Commission estimates the
average total cost to each of these
entities will be minimal, requiring on
average 10 hours, or $745.00. According
to SBA guidance, the determination of
significance of impact ‘‘should be seen
as relative to the size of the business,
the size of the competitor’s business,
and the impact the regulation has on
larger competitors.’’ 152 The Commission
CFR 380.4(a)(15) (2015).
U.S.C. 601–612 (2012).
150 13 CFR 121.201, Sector 22 (Utilities), NAICS
code 221121 (Electric Bulk Power Transmission and
Control).
151 The NERC Compliance Registry lists 80
entities that administer a transmission tariff and
provide transmission service. The Commission
identifies only 74 as being subject to the proposed
requirements because 6 are Canadian entities and
are not under the Commission’s jurisdiction.
152 U.S. Small Business Administration, A Guide
for Government Agencies: How to Comply with the
does not consider the estimated burden
to be a significant economic impact. As
a result, the Commission believes this
NOPR would not have a significant
economic impact on a substantial
number of small entities.
71. The Commission estimates that
the total annual number of new nonsynchronous interconnections per year
for the first few years of potential
implementation under this NOPR would
be approximately 200, representing
approximately 5,000 MW of installed
capacity. Of these, the Commission
estimates that the majority are small
entities. The Commission estimates the
average total cost to each of these
entities will be minimal, requiring on
average approximately $3,300 per MW
of installed capacity. According to SBA
guidance, the determination of
significance of impact ‘‘should be seen
as relative to the size of the business,
the size of the competitor’s business,
and the impact the regulation has on
larger competitors.’’ The Commission
does not consider the estimated burden
to be a significant economic impact on
these entities because the cost is
relatively minimal compared to the
average capital cost per MW for wind
and solar PV generation.153
Additionally, the Commission does not
believe that there will be substantial
additional costs for new synchronous
generators because synchronous
generators already come equipped with
governors that provide the capability to
provide primary frequency response.
Accordingly, the Commission believes
that this NOPR would not have a
significant economic impact on a
substantial number of small entities.
VI. Comment Procedures
72. The Commission invites interested
persons to submit comments on the
matters and issues proposed in this
notice to be adopted, including any
related matters or alternative proposals
that commenters may wish to discuss.
Comments are due January 24, 2017.
Comments must refer to Docket No.
RM16–6–000, and must include the
commenter’s name, the organization
they represent, if applicable, and their
address in their comments.
148 18
149 5
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Regulatory Flexibility Act, at 18 (May 2012), https://
www.sba.gov/sites/default/files/advocacy/rfaguide_
0512_0.pdf.
153 LBNL estimates that capital cost per MW of
installed wind capacity is $1,690,000. See LBNL
2015 Wind Market Report (Aug. 2016), https://
emp.lbl.gov/sites/all/files/2015windtechreport.final_.pdf). NREL estimates that the
capital cost per MW of installed solar PV capacity
is $1,770,000. See NREL U.S. Photovoltaic Prices
and Cost Breakdowns (Sep. 2015), https://
www.nrel.gov/docs/fy15osti/64746.pdf.
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73. The Commission encourages
comments to be filed electronically via
the eFiling link on the Commission’s
Web site at https://www.ferc.gov. The
Commission accepts most standard
word processing formats. Documents
created electronically using word
processing software should be filed in
native applications or print-to-PDF
format and not in a scanned format.
Commenters filing electronically do not
need to make a paper filing.
74. Commenters that are not able to
file comments electronically must send
an original of their comments to:
Federal Energy Regulatory Commission,
Secretary of the Commission, 888 First
Street NE., Washington, DC 20426.
75. All comments will be placed in
the Commission’s public files and may
be viewed, printed, or downloaded
remotely as described in the Document
Availability section below. Commenters
on this proposal are not required to
serve copies of their comments on other
commenters.
VII. Document Availability
76. 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) and in the Commission’s
Public Reference Room during normal
business hours (8:30 a.m. to 5:00 p.m.
Eastern time) at 888 First Street NE.,
Room 2A, Washington, DC 20426.
77. From the Commission’s Home
Page on the Internet, this information is
available on eLibrary. The full text of
this document is available on eLibrary
in PDF and Microsoft Word format for
85189
viewing, printing, and/or downloading.
To access this document in eLibrary,
type the docket number excluding the
last three digits of this document in the
docket number field.
78. User assistance is available for
eLibrary and the Commission’s Web site
during normal business hours from the
Commission’s Online Support at (202)
502–6652 (toll free at 1–866–208–3676)
or email at ferconlinesupport@ferc.gov,
or the Public Reference Room at (202)
502–8371, TTY (202)502–8659. Email
the Public Reference Room at
public.referenceroom@ferc.gov.
By direction of the Commission.
Issued: November 17, 2016.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
Appendix
LIST OF COMMENTERS (DOCKET NO. RM16–6–000)
AES Companies .................................................
APPA, et al .........................................................
AWEA .................................................................
Apex ....................................................................
APS .....................................................................
Bonneville ...........................................................
CAISO .................................................................
Chelan County ....................................................
California Cities ...................................................
EEI ......................................................................
EDP .....................................................................
EPRI ....................................................................
EPSA, et al .........................................................
ELCON ................................................................
ESA .....................................................................
Grid Storage Consulting .....................................
Howard F. Illian ...................................................
Idaho Power ........................................................
Indicated ISOs/RTOs ..........................................
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IEEE–P1547 Working Group ..............................
IEEE–PES ...........................................................
ITC, et al .............................................................
Manitoba .............................................................
Microgrids Resources Coalition ..........................
MISO ...................................................................
MISO TOs ...........................................................
NARUC ...............................................................
NRECA ...............................................................
NERC ..................................................................
North American Generator Forum ......................
Nuclear Energy Institute .....................................
PG&E ..................................................................
Peak Reliability ...................................................
PJM Utilities Coalition .........................................
Powerex ..............................................................
Public Interest Organizations ..............................
Ralph D. Masiello ...............................................
SDG&E ...............................................................
Solar City ............................................................
SoCal Edison ......................................................
Southern Company .............................................
Steel Producers ..................................................
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AES Corporation/AES Energy Storage/Dayton Power and Light Company/Indianapolis Power
and Light Company.
American Public Power Association/Large Public Power Council/Transmission Access Policy
Study Group.
American Wind Energy Association.
Apex Compressed Air Energy Storage.
Arizona Public Service Company.
Bonneville Power Administration.
California Independent System Operator.
Chelan County Public Utility District.
City of Anaheim/City of Azusa/City of Banning/City of Colton/City of Pasadena/City of Riverside.
Edison Electric Institute.
EDP Renewables North America.
Electric Power Research Institute.
Electric Power Supply Association/Independent Power Producers of New York/New England
Power Generators Association/Western Power Trading Forum.
Electricity Consumers Resource Council.
Energy Storage Association.
Grid Storage Consulting.
Howard F. Illian
Idaho Power Company.
Independent Electricity System Operator/ISO New England/New York Independent System
Operator/PJM Interconnection/Southwest Power Pool.
Institute of Electrical and Electronics Engineers (IEEE) P1547 Standards Working Group.
IEEE Power and Energy Society Technical Council.
International Transmission Company/Michigan Electric Transmission Company/ITC Great
Plains/ITC Midwest.
Manitoba Hydro.
Microgrids Resources Coalition.
Midcontinent Independent System Operator.
Midcontinent Independent System Operator Transmission Owners.
National Association of Regulatory Utility Commissioners.
National Rural Electric Cooperative Association.
North American Electric Reliability Corporation.
North American Generator Forum.
Nuclear Energy Institute.
Pacific Gas and Electric Company.
Peak Reliability.
PJM Utilities Coalition.
Powerex Corp.
Public Interest Organizations.
Ralph D. Masiello.
San Diego Gas & Electric Company.
Solar City Corporation.
Southern California Edison Company.
Southern Company.
Steel Producers.
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Federal Register / Vol. 81, No. 227 / Friday, November 25, 2016 / Proposed Rules
LIST OF COMMENTERS (DOCKET NO. RM16–6–000)—Continued
Tacoma Power ....................................................
TVA .....................................................................
Tri-State Generation ...........................................
Union of Concerned Scientists ...........................
WIRAB ................................................................
FOR FURTHER INFORMATION CONTACT:
[FR Doc. 2016–28321 Filed 11–23–16; 8:45 am]
Concerning the regulations, Neil S.
Sandhu or Linda S.F. Marshall at (202)
317–6700; concerning submissions of
comments, the hearing, and/or being
placed on the building access list to
attend the hearing, Oluwafunmilayo
(Funmi) Taylor at (202) 317–6901 (not
toll-free numbers).
SUPPLEMENTARY INFORMATION:
BILLING CODE 6717–01–P
DEPARTMENT OF THE TREASURY
Internal Revenue Service
26 CFR Part 1
[REG–107424–12]
RIN 1545–BK95
Update to Minimum Present Value
Requirements for Defined Benefit Plan
Distributions
Internal Revenue Service (IRS),
Treasury.
ACTION: Notice of proposed rulemaking
and notice of public hearing.
AGENCY:
This document contains
proposed regulations providing
guidance relating to the minimum
present value requirements applicable
to certain defined benefit pension plans.
These proposed regulations would
provide guidance on changes made by
the Pension Protection Act of 2006 and
would provide other modifications to
these rules as well. These regulations
would affect participants, beneficiaries,
sponsors, and administrators of defined
benefit pension plans. This document
also provides a notice of a public
hearing on these proposed regulations.
DATES: Written or electronic comments
must be received by February 23, 2017.
Outlines of topics to be discussed at the
public hearing scheduled for March 7,
2017, must be received by February 23,
2017.
ADDRESSES: Send submissions to:
CC:PA:LPD:PR (REG–107424–12), Room
5203, Internal Revenue Service, P.O.
Box 7604, Ben Franklin Station,
Washington, DC 20044. Submissions
may be hand-delivered Monday through
Friday between the hours of 8 a.m. and
4 p.m. to: CC:PA:LPD:PR (REG–107424–
12), Courier’s Desk, Internal Revenue
Service, 1111 Constitution Avenue NW.,
Washington, DC, or sent electronically,
via the Federal eRulemaking Portal at
https://www.regulations.gov (IRS REG–
107424–12). The public hearing will be
held in the IRS Auditorium, Internal
Revenue Building, 1111 Constitution
Avenue NW., Washington, DC.
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SUMMARY:
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Tacoma Power.
Tennessee Valley Authority.
Tri-State Generation and Transmission Association.
Union of Concerned Scientists.
Western Interconnection Regional Advisory Body.
Background
Section 401(a)(11) of the Internal
Revenue Code (Code) provides that, in
order for a defined benefit plan to
qualify under section 401(a), except as
provided under section 417, in the case
of a vested participant who does not die
before the annuity starting date, the
accrued benefit payable to such
participant must be provided in the
form of a qualified joint and survivor
annuity. In the case of a vested
participant who dies before the annuity
starting date and who has a surviving
spouse, a defined benefit plan must
provide a qualified preretirement
survivor annuity to the surviving spouse
of such participant, except as provided
under section 417.
Section 411(d)(6)(B) provides that a
plan amendment that has the effect of
eliminating or reducing an early
retirement benefit or a retirement-type
subsidy, or eliminating an optional form
of benefit, with respect to benefits
attributable to service before the
amendment is treated as impermissibly
reducing accrued benefits. However, the
last sentence of section 411(d)(6)(B)
provides that the Secretary may by
regulations provide that section
411(d)(6)(B) does not apply to a plan
amendment that eliminates an optional
form of benefit (other than a plan
amendment that has the effect of
eliminating or reducing an early
retirement benefit or a retirement-type
subsidy).
Section 417(e)(1) provides that a plan
may provide that the present value of a
qualified joint and survivor annuity or
a qualified preretirement survivor
annuity will be immediately distributed
if that present value does not exceed the
amount that can be distributed without
the participant’s consent under section
411(a)(11). Section 417(e)(2) provides
that, if the present value of the qualified
joint and survivor annuity or the
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qualified preretirement survivor annuity
exceeds the amount that can be
distributed without the participant’s
consent under section 411(a)(11), then a
plan may immediately distribute the
present value of a qualified joint and
survivor annuity or the qualified
preretirement survivor annuity only if
the participant and the spouse of the
participant (or where the participant has
died, the surviving spouse) consent in
writing to the distribution.
Section 417(e)(3)(A) provides that the
present value shall not be less than the
present value calculated by using the
applicable mortality table and the
applicable interest rate.1
Section 417(e)(3)(B) of the Code, as
amended by section 302 of the Pension
Protection Act of 2006 (PPA ’06), Public
Law 109–280, 120 Stat. 780 (2006),
provides that the term ‘‘applicable
mortality table’’ means a mortality table,
modified as appropriate by the
Secretary, based on the mortality table
specified for the plan year under section
430(h)(3)(A) (without regard to section
430(h)(3)(C) or (3)(D)).
Section 417(e)(3)(C) of the Code, as
amended by section 302 of PPA ‘06,
provides that the term ‘‘applicable
interest rate’’ means the adjusted first,
second, and third segment rates applied
under rules similar to the rules of
section 430(h)(2)(C) of the Code for the
month before the date of the distribution
or such other time as the Secretary may
prescribe by regulations. However, for
purposes of section 417(e)(3), these rates
are to be determined without regard to
the segment rate stabilization rules of
section 430(h)(2)(C)(iv). In addition,
under section 417(e)(3)(D), these rates
are to be determined using the average
yields for a month, rather than the 24month average used under section
430(h)(2)(D).
Section 411(a)(13) of the Code, as
added by section 701(b) of PPA ‘06,
provides that an ‘‘applicable defined
benefit plan,’’ as defined by section
411(a)(13)(C), is not treated as failing to
meet the requirements of section 417(e)
1 Under section 411(a)(11)(B), the same applicable
mortality table and applicable interest rate are used
for purposes of determining whether the present
value of a participant’s nonforfeitable accrued
benefit exceeds the maximum amount that can be
immediately distributed without the participant’s
consent.
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Agencies
[Federal Register Volume 81, Number 227 (Friday, November 25, 2016)]
[Proposed Rules]
[Pages 85176-85190]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-28321]
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM16-6-000]
Essential Reliability Services and the Evolving Bulk-Power
System--Primary Frequency Response
AGENCY: Federal Energy Regulatory Commission, Department of Energy.
ACTION: Notice of proposed rulemaking.
-----------------------------------------------------------------------
SUMMARY: The Federal Energy Regulatory Commission (Commission) proposes
to revise its regulations to require all newly interconnecting large
and small generating facilities, both synchronous and non-synchronous,
to install and enable primary frequency response capability as a
condition of interconnection. To implement these requirements, the
Commission proposes to revise the pro forma Large Generator
Interconnection Agreement (LGIA) and the pro forma Small Generator
Interconnection Agreement (SGIA). The proposed changes are designed to
address the increasing impact of the evolving generation resource mix
and to ensure that the relevant provisions of the pro forma LGIA and
pro forma SGIA are just, reasonable, and not unduly discriminatory or
preferential. The Commission also seeks comment on whether its
proposals in this Notice of Proposed Rulemaking are sufficient at this
time to ensure adequate levels of primary frequency response, or
whether additional reforms are needed.
DATES: Comments are due January 24, 2017.
ADDRESSES: Comments, identified by docket number, may be filed in the
following ways:
Electronic Filing through https://www.ferc.gov. Documents
created electronically using word processing software should be filed
in native applications or print-to-PDF format and not in a scanned
format.
Mail/Hand Delivery: Those unable to file electronically
may mail or hand-deliver comments to: Federal Energy Regulatory
Commission, Secretary of the Commission, 888 First Street NE.,
Washington, DC 20426.
Instructions: For detailed instructions on submitting comments and
additional information on the rulemaking process, see the Comment
Procedures Section of this document.
FOR FURTHER INFORMATION CONTACT:
Jomo Richardson (Technical Information), Office of Electric
Reliability, Federal Energy Regulatory Commission, 888 First Street
NE., Washington, DC 20426, (202) 502-6281, Jomo.Richardson@ferc.gov.
Mark Bennett (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE., Washington,
DC 20426, (202) 502-8524, Mark.Bennett@ferc.gov.
SUPPLEMENTARY INFORMATION:
1. In this Notice of Proposed Rulemaking (NOPR), the Federal Energy
Regulatory Commission (Commission) proposes to modify the pro forma
Large Generator Interconnection Agreement (LGIA) and the pro forma
Small Generator Interconnection Agreement (SGIA), pursuant to its
authority under section 206 of the Federal Power Act (FPA) to ensure
that rates, terms and conditions of jurisdictional service remain just
and reasonable and not unduly discriminatory or preferential.\1\ The
proposed modifications would require all new large and small generating
facilities, including both synchronous and non-synchronous,
interconnecting with a LGIA or SGIA to install, maintain and operate
equipment capable of providing primary frequency response as a
condition of interconnection. The Commission also proposes to establish
certain operating requirements, including maximum droop and deadband
parameters in the pro forma LGIA and pro forma SGIA. The Commission
does not propose to apply these requirements to generating facilities
regulated by the Nuclear Regulatory Commission. In addition, the
Commission does not propose in these reforms to impose a headroom
requirement for new generating facilities. The Commission also does not
propose to mandate that new generating facilities receive any
compensation for complying with the proposed requirements in this NOPR.
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\1\ 16 U.S.C. 824e (2012).
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2. The proposed revisions address the Commission's concerns that
the existing pro forma LGIA contains limited primary frequency response
requirements that apply only to synchronous generating facilities and
do not account for recent technological advancements that have enabled
new non-synchronous generating facilities to now have primary frequency
response capabilities. Further, the Commission believes that it may be
unduly discriminatory or preferential to impose primary frequency
response requirements only on new large generating facilities but not
on new small generating facilities, and the reforms proposed here would
impose
[[Page 85177]]
comparable primary frequency response requirements on both new large
and small generating facilities.
3. In addition, and as discussed below in paragraph 57, the
Commission also seeks comment on whether its proposals in this NOPR are
sufficient at this time to ensure adequate levels of primary frequency
response, or whether additional reforms are needed.
4. The Commission seeks comment on the proposed reforms and
requests for comment sixty (60) days after publication of this NOPR in
the Federal Register.
I. Background
A. Frequency Response
5. Reliable operation of an Interconnection \2\ depends on
maintaining frequency within predetermined boundaries above and below a
scheduled value, which is 60 Hertz (Hz) in North America. Changes in
frequency are caused by changes in the balance between load and
generation, such as the sudden loss of a large generator or a large
amount of load. If frequency deviates too far above or below its
scheduled value, it could potentially result in under frequency load
shedding (UFLS), generation tripping, or cascading outages.\3\
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\2\ An Interconnection is a geographic area in which the
operation of the electric system is synchronized. In the continental
United States, there are three Interconnections, namely the Eastern,
Texas, and Western Interconnections.
\3\ UFLS is designed for use in extreme conditions to stabilize
the balance between generation and load. Under frequency protection
schemes are drastic measures employed if system frequency falls
below a specified value. See Automatic Underfrequency Load Shedding
and Load Shedding Plans Reliability Standards, Notice of Proposed
Rulemaking, FERC Stats. & Regs. ] 32,682, at PP 4-10 (2011) (Order
No. 763 NOPR) at PP 4-10.
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6. Mitigation of frequency deviations after the sudden loss of
generation or load is driven by three primary factors: inertial
response, primary frequency response, and secondary frequency
response.\4\ Primary frequency response actions begin within seconds
after system frequency changes and are mostly provided by the automatic
and autonomous actions (i.e., outside of system operator control) of
turbine-governors, while some response is provided by frequency
responsive loads.\5\ Primary frequency response actions are intended to
arrest abnormal frequency deviations and ensure that system frequency
remains within acceptable bounds. An important goal for system planners
and operators is for the frequency nadir,\6\ during large disturbances,
to remain above the first stage of UFLS set points within an
Interconnection.
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\4\ In the Notice of Inquiry issued in Docket No. RM16-6-000 on
Feb. 8, 2016, the Commission provided detailed discussion of how
inertia, primary frequency response, and secondary frequency
response interact to mitigate frequency deviations. Essential
Reliability Services and the Evolving Bulk-Power System--Primary
Frequency Response, 154 FERC ] 61,117, at PP 3-7 (2016) (NOI). See
also Use of Frequency Response Metrics to Assess the Planning and
Operating Requirements for Reliable Integration of Variable
Renewable Generation, Lawrence Berkeley National Laboratory, at 13-
14 (Dec. 2010), https://energy.lbl.gov/ea/certs/pdf/lbnl-4142e.pdf
(LBNL 2010 Report).
\5\ NOI, 154 FERC ] 61,117 at P 6. The Commission also noted
that regulation service is different than primary frequency response
because generating facilities that provide regulation respond to
automatic generation control signals and regulation service is
centrally coordinated by the system operator, whereas primary
frequency response service, in contrast, is autonomous and is not
centrally coordinated. Schedule 3 of the pro forma Open Access
Transmission Tariff (OATT) bundles these different services
together, despite their differences. See Id. n.66.
\6\ The point at which the frequency decline is arrested
(following the sudden loss of generation) is called the frequency
nadir, and represents the point at which the net primary frequency
response (real power) output from all generating units and the
decrease in power consumed by the load within an Interconnection
matches the net initial loss of generation (in megawatts (MW)).
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7. Frequency response is a measure of an Interconnection's ability
to arrest and stabilize frequency deviations following the sudden loss
of generation or load, and is affected by the collective responses of
generation and load throughout the Interconnection. When considered in
aggregate, the primary frequency response provided by generators within
an Interconnection has a significant impact on the overall frequency
response. NERC Reliability Standard BAL-003-1.1 defines the amount of
frequency response needed from balancing authorities \7\ to maintain
Interconnection frequency within predefined bounds and includes
requirements for the measurement and provision of frequency
response.\8\ While NERC Reliability Standard BAL-003-1.1 establishes
requirements for balancing authorities, it does not include any
requirements for individual generator owners or operators.\9\
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\7\ NERC's Glossary of Terms defines a balancing authority as
``(t)he responsible entity that integrates resource plans ahead of
time, maintains load-interchange-generation balance within a
balancing authority area, and supports Interconnection frequency in
real time.''
\8\ Frequency Response and Frequency Bias Setting Reliability
Standard, Order No. 794, 146 FERC ] 61,024 (2014).
\9\ The Commission has also accepted Regional Reliability
Standard BAL-001-TRE-01 (Primary Frequency Response in the ERCOT
Region) as mandatory and enforceable, which does establish
requirements for generator owners and operators with respect to
governor control settings and the provision of primary frequency
response within the Electric Reliability Council of Texas (ERCOT)
region. North American Electric Reliability Corporation, 146 FERC ]
61,025 (2014).
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8. Unless otherwise required by tariffs or interconnection
agreements, generator owners and operators can independently decide
whether units are configured to provide primary frequency response.\10\
The magnitude and duration of a generator's response to frequency
deviations is generally determined by the settings of the unit's
governor \11\ (or equivalent controls) and other plant level (e.g.,
``outer-loop'') control systems. In particular, the governor's droop
and deadband settings have a significant impact on the unit's provision
of primary frequency response. In addition, plant-level or ``outer-
loop'' controls, unless properly configured, can override or nullify a
generator's governor response and return the unit to operate at a
scheduled pre-disturbance megawatt set-point.\12\ In 2010, NERC
conducted a survey of generator owners and operators and found that
only approximately 30 percent of generators in the Eastern
Interconnection provided primary frequency response, and that only
approximately 10 percent of generators provided sustained primary
frequency response.\13\ This suggests that many generators within the
Interconnection disable or otherwise set their governors or outer-loop
controls such that they provide little to no primary frequency
response.\14\
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\10\ See NOI, 154 FERC ] 61,117 at PP 18-19.
\11\ A governor is an electronic or mechanical device that
implements primary frequency response on a generator via a droop
parameter. Droop refers to the variation in real power (MW) output
due to variations in system frequency and is typically expressed as
a percentage (e.g., 5 percent droop). Droop reflects the amount of
frequency change from nominal (e.g., 5 percent of 60 Hz is 3 Hz)
that is necessary to cause the main prime mover control mechanism of
a generating facility to move from fully closed to fully open. A
governor also has a deadband parameter which establishes a minimum
frequency deviation (e.g., 0.036 Hz) from nominal that
must be exceeded in order for the governor to act.
\12\ For more discussion on ``premature withdrawal'' of primary
frequency response, see NOI, 154 FERC ] 61,117 at PP 49-50.
\13\ See NERC Frequency Response Initiative Report: The
Reliability Role of Frequency Response (Oct. 2012), https://www.nerc.com/docs/pc/FRI_Report_10-30-12_Master_w-appendices.pdf
(NERC Frequency Response Initiative Report) at 95.
\14\ However, as noted below, some commenters note that nuclear
generating units are restricted by their U.S. Nuclear Regulatory
Commission operating licenses regarding the provision of primary
frequency response.
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9. Declining frequency response performance has been an industry
concern for many years. NERC, in conjunction with EPRI, initiated its
first examination of declining frequency response and governor response
in 1991.\15\ More recently, as noted in the
[[Page 85178]]
NOI, while the three U.S. Interconnections currently exhibit adequate
frequency response performance above their Interconnection Frequency
Response Obligations,\16\ there has been a significant decline in the
frequency response performance of the Western and Eastern
Interconnections.\17\
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\15\ NERC Frequency Response Initiative Report at 22.
\16\ The Interconnection Frequency Response Obligations are
established by NERC and are designed to require sufficient frequency
response for each Interconnection (i.e., the Eastern, ERCOT, Quebec
and Western Interconnections) to arrest frequency declines even for
severe, but possible, contingencies.
\17\ NOI, 154 FERC ] 61,117 at P 20.
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B. Prior Commission Actions
10. In Order Nos. 2003 \18\ and 2006,\19\ the Commission adopted
standard procedures for the interconnection of large and small
generating facilities, including the development of standardized pro
forma generator interconnection agreements and procedures. The
Commission required public utility transmission providers \20\ to file
revised OATTs containing these standardized provisions, and use the
LGIA and SGIA to provide non-discriminatory interconnection service to
Large Generators (i.e., generating facilities having a capacity of more
than 20 MW) and Small Generators (i.e., generators having a capacity of
no more than 20 MW). The pro forma LGIA and pro forma SGIA have since
been revised through various subsequent proceedings.\21\
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\18\ Standardization of Generator Interconnection Agreements and
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146 (2003),
order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ] 31,160,
order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ] 31,171
(2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. ]
31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util.
Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552
U.S. 1230 (2008).
\19\ Standardization of Small Generator Interconnection
Agreements and Procedures, Order No. 2006, FERC Stats. & Regs. ]
31,180, order on reh'g, Order No. 2006-A, FERC Stats. & Regs. ]
31,196 (2005), order granting clarification, Order No. 2006-B, FERC
Stats. & Regs. ] 31,221 (2006).
\20\ A public utility is a utility that owns, controls, or
operates facilities used for transmitting electric energy in
interstate commerce, as defined by the FPA. See 16 U.S.C. 824(e)
(2012). A non-public utility that seeks voluntary compliance with
the reciprocity condition of an OATT may satisfy that condition by
filing an OATT, which includes a LGIA and SGIA. See Order No. 2003,
FERC Stats. & Regs. ] 31,146, at PP 840-845.
\21\ E.g., Small Generator Interconnection Agreements and
Procedures, Order No. 792, 145 FERC ] 61,159 (2013), clarifying,
Order No. 792-A, 146 FERC ] 61,214 (2014); Reactive Power
Requirements for Non-Synchronous Generation, Order No. 827, 81 FR
40,793 (Jun. 23, 2016), 155 FERC ] 61,277 (2016); Requirements for
Frequency and Voltage Ride Through Capability of Small Generating
Facilities, Order No. 828, 81 FR 50,290 (Aug. 1, 2016), 156 FERC ]
61,062 (2016).
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11. As relevant here, the pro forma LGIA and pro forma SGIA are
largely silent on any requirements with respect to primary frequency
response. In particular, the only requirement in the pro forma LGIA or
pro forma SGIA related to primary frequency response is contained
within current Article 9.6.2.1 of the pro forma LGIA (Governors and
Regulators), which provides that if speed governors are installed, they
should be operated in automatic mode.\22\ A speed governor implements
the primary frequency response provided by a synchronous generating
facility; however, Article 9.6.2.1 does not address governor settings
or plant-level controls, which also affect the ability of a generating
facility to provide primary frequency response. In addition, Article
9.6.2.1 does not require the installation of the necessary equipment
for frequency response capability (i.e., governors or equivalent
controls). Finally, the pro forma SGIA does not contain any provisions
related to primary frequency response.
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\22\ Article 9.6.2.1 of the pro forma LGIA.
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C. Efforts To Evaluate the Impacts of the Changing Resource Mix
12. The Commission's pro forma generator interconnection agreements
and procedures were developed at a time when traditional synchronous
generating facilities with standard governor controls and large
rotational inertia were the predominant sources of electricity
generation. However, the nation's resource mix has undergone
significant change since the issuance of Order Nos. 2003 and 2006. This
transformation has been characterized by the retirement of baseload,
synchronous generating facilities and the integration of more
distributed generation, demand response, and natural gas generating
facilities, and the rapid expansion of non-synchronous variable energy
resources (VERs) such as wind and solar.\23\ For example, the U.S.
Energy Information Administration (EIA) has observed that the U.S.
added approximately 13 gigawatts (GW) of wind, 6.2 GW of utility scale
solar photovoltaic (PV), and 3.6 GW of distributed solar PV generating
facilities in 2014 and 2015.\24\ Conversely, NERC has reported \25\
that almost 42 GW of synchronous generating facilities (e.g., coal,
nuclear, and natural gas) have retired between 2011 and 2014, and the
EIA recently reported that nearly 14 GW of coal and 3 GW of natural gas
generating facilities retired in 2015.\26\
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\23\ The term VER is defined as a device for the production of
electricity that is characterized by an energy source that: (1) Is
renewable; (2) cannot be stored by the facility owner or operator;
and (3) has variability that is beyond the control of the facility
owner or operator. See, e.g., Integration of Variable Energy
Resources, Order No. 764, FERC Stats. & Regs. ] 31,331, at P 210
(2012).
\24\ See, U.S. electric generation capacity additions, 2015 vs.
2014, EIA (March 2016), https://www.eia.gov/todayinenergy/detail.php?id=25492.
\25\ See NERC 2015 LTRA (Dec. 2015), https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2015LTRA%20-%20Final%20Report.pdf.
\26\ See Electricity generating capacity retired in 2015 by fuel
and technology, EIA (May 2016), https://www.eia.gov/todayinenergy/detail.php?id=25272.
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13. While technological advancements have enabled wind and solar
generating facilities to now have the ability to provide primary
frequency response, this functionality has not historically been a
standard feature that was included and enabled on non-synchronous
generating facilities. Moreover, wind and solar generating facilities
typically operate at their maximum operating output, leaving no
capacity (or ``headroom'') \27\ to provide primary frequency response
during under-frequency conditions.
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\27\ Headroom refers to the difference between the current
operating point of a generator and its maximum operating capability,
and represents the potential amount of additional energy that can be
provided by the generating facility in real-time.
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14. Given the changes in the resource mix and concerns about the
significant decline in frequency response for the Eastern and Western
Interconnections,\28\ NERC has undertaken several initiatives to
evaluate the impacts of the changing resource mix, particularly with
respect to primary frequency response. For example, in 2014, NERC
initiated the Essential Reliability Services Task Force (Task Force) to
analyze and better understand the impacts of the changing resource mix
and develop technical assessments of essential reliability
services.\29\ The Task Force focused on three essential reliability
services: Frequency support, ramping capability, and voltage
support.\30\ The Task Force considered the seven ancillary
[[Page 85179]]
services \31\ adopted by the Commission in Order Nos. 888 \32\ and 890
\33\ as a subset of the essential reliability services that may need to
be augmented by additional services as the Bulk-Power System \34\
characteristics change.
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\28\ See NERC Frequency Response Initiative Industry Advisory--
Generator Governor Frequency Response, at slide 10 (Apr. 2015),
https://www.nerc.com/pa/rrm/Webinars%20DL/Generator_Governor_Frequency_Response_Webinar_April_2015.pdf. (NERC
2015 Frequency Response Webinar). See also LBNL 2010 Report at pp
xiv-xv.
\29\ Essential reliability services are referred to as elemental
reliability building blocks from resources (generation and load)
that are necessary to maintain the reliability of the Bulk-Power
System. See Essential Reliability Services Task Force Scope
Document, at 1 (Apr. 2014), https://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/Scope_ERSTF_Final.pdf.
\30\ Essential Reliability Services Task Force Measures Report,
at 22 (Dec. 2015), https://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/ERSTF%20Framework%20Report%20-%20Final.pdf.
\31\ The seven pro forma ancillary services set forth in Order
Nos. 888 and 890 are: (1) Scheduling, System Control and Dispatch
Service; (2) Reactive Supply and Voltage Control from Generation
Sources Service; (3) Regulation and Frequency Response Service; (4)
Energy Imbalance Service; (5) Operating Reserve--Spinning Reserve
Service; (6) Operating Reserve--Supplemental Reserve Service; and
(7) Generator Imbalance Service.
\32\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, FERC Stats. & Regs. ] 31,036 (1996), order on reh'g,
Order No. 888-A, FERC Stats. & Regs. ] 31,048, order on reh'g, Order
No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 888-C,
82 FERC ] 61,046 (1998), aff'd in relevant part sub nom.
Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C.
Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
\33\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, FERC Stats. & Regs. ] 31,241,
order on reh'g, Order No. 890-A, FERC Stats. & Regs. ] 31,261
(2007), order on reh'g, Order No. 890-B, 123 FERC ] 61,299 (2008),
order on reh'g, Order No. 890-C, 126 FERC ] 61,228, order on
clarification, Order No. 890-D, 129 FERC ] 61,126 (2009).
\34\ Section 215(a)(1) of the Federal Power Act (FPA), 16 U.S.C.
824o(a)(1) (2012) defines ``Bulk-Power System'' as those
``facilities and control systems necessary for operating an
interconnected electric energy transmission network (or any portion
thereof) [and] electric energy from generating facilities needed to
maintain transmission system reliability.'' The term does not
include facilities used in the local distribution of electric
energy. See also Mandatory Reliability Standards for the Bulk-Power
System, Order No. 693, FERC Stats. & Regs. ] 31,242 at P 76, order
on reh'g, Order No. 693-A, 120 FERC ] 61,053 (2007).
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15. The Task Force did not recommend new reliability standards or
specific actions to alter the existing suite of ancillary services;
however, it did make certain conclusions with regard to primary
frequency response. Specifically, the Task Force concluded that it is
prudent and necessary to ensure that primary frequency response
capabilities are present in the future generation resource mix, and
recommended that all new generators support the capability to manage
frequency.\35\
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\35\ Essential Reliability Services Task Force Measures Report
at vi.
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16. In addition, as part of its ongoing analysis of primary
frequency response concerns, NERC observed in a 2012 report that a
number of generators implemented deadband settings that were so wide as
to effectively defeat the ability to provide primary frequency
response.\36\ The report also notes that many generators provide
frequency response in the wrong direction during a disturbance.\37\
Additionally, in February 2015, NERC issued an Industry Advisory that
determined that a significant portion of generators within the Eastern
Interconnection use deadbands or governor control settings that either
inhibit or prevent the provision of primary frequency response.\38\
Moreover, as noted in the NOI, NERC observed in 2015 that in many
conventional steam plants, deadband settings exceed 0.036
Hz, resulting in primary frequency response that is not sustained, and
that the vast majority of the gas turbine fleet is not frequency
responsive.\39\ In response to these issues and other concerns, NERC's
Operating Committee approved a voluntary Primary Frequency Control
Guideline that contains recommended settings for generator governors
and other plant control systems, and encourages generators within the
three U.S. Interconnections to provide sustained and effective primary
frequency response.\40\ NERC's Guideline recommends maximum 5 percent
droop and 0.036 Hz deadband settings for most generating
facilities.\41\
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\36\ NERC Frequency Response Initiative Report at 92.
\37\ NERC Frequency Response Initiative Report at 96-97.
\38\ NERC Generator Governor Frequency Response Industry
Advisory (Feb. 2015), https://www.nerc.com/pa/rrm/bpsa/Alerts%20DL/2015%20Alerts/NERC%20Alert%20A-2015-02-05-01%20Generator%20Governor%20Frequency%20Response.pdf.
\39\ NOI, 154 FERC ] 61,117 at P 50 (citing to NERC 2015
Frequency Response Webinar at 1).
\40\ See NERC Primary Frequency Control Guideline Final Draft
(Dec. 2015), https://www.nerc.com/comm/OC/Reliability%20Guideline%20DL/Primary_Frequency_Control_final.pdf
(NERC Primary Frequency Control Guideline). See also NERC Operating
Committee Meeting Minutes (Jan. 2016), https://www.nerc.com/comm/OC/AgendasHighlightsMinutes/Operating%20Committee%20Minutes%20-%20Dec%2015-16%202015-Final.pdf.
\41\ See NERC Primary Frequency Control Guideline at 7-9.
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D. Initiatives by Individual Transmission Providers
17. While the pro forma LGIA and pro forma SGIA do not provide
specific requirements related to frequency response, some public
utility transmission providers have included provisions related to
primary frequency response in their LGIA, SGIA, OATTs, and/or business
practice manuals.
18. For example, ISO New England Inc. (ISO-NE) and New York
Independent System Operator, Inc. (NYISO) have adopted provisions to
their LGIAs that establish more specific requirements for governor
operation.\42\ In particular, ISO-NE requires each generator within its
region with a capability of 10 MW or more, including VERs, to operate
with a functioning governor with specified droop and deadband settings,
i.e., maximum 5 percent droop and 0.036 Hz deadband, and to
also ensure that the provision of primary frequency response is not
inhibited by the effects of outer-loop controls.\43\
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\42\ See ISO-NE, Transmission, Markets and Services Tariff,
Schedule 22 Large Generator Interconnection Procedures (9.0.0),
Appendix 6, 9.6.2.2; NYISO, NYISO Tariffs, NYISO OATT, 30.14 OATT
Att. X Appendices (8.0.0), Appendix 6, 9.5.4.
\43\ See ISO-NE's Operating Procedure No. 14 I (Governor
Control), https://www.iso-ne.com/rules_proceds/operating/isone/op14/op14_rto_final.pdf.
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19. PJM Interconnection, L.L.C. (PJM) has implemented governor
droop and deadband requirements, i.e., maximum 5 percent droop and
0.036 Hz deadband, for all generating facilities excluding
nuclear facilities with a gross plant/facility aggregate nameplate
rating greater than 75 MVA.\44\ PJM also recently added new
interconnection requirements requiring new non-synchronous generators
to interconnect with ``enhanced inverters'' that have various
capabilities including, among other things, the ability to provide
primary frequency response.\45\
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\44\ PJM's pro forma interconnection agreements obligate
interconnection customers within its region to abide by all PJM
rules and procedures, including rules set forth in PJM's Manuals
(See PJM Tariff, Attachment O 8.0). See also PJM Manual 14D 7.1.1
(Generator Real-Power Control), https://www.pjm.com/~/media/
documents/manuals/m14d.ashx.
\45\ PJM Interconnection, L.L.C., 151 FERC ] 61,097, at n.58
(2015).
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20. Midcontinent Independent System Operator, Inc. (MISO) requires
governor operation as a condition for providing regulating reserve but
does not require specific settings.\46\ Also, the Commission recently
accepted tariff provisions proposed by the California Independent
System Operator Corporation (CAISO) to require governor operation,
specified droop and deadband settings, i.e., maximum 5 percent droop
and 0.036 Hz deadband, and provisions for sustained primary
frequency response for its participating generators that have
traditional governor controls.\47\
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\46\ See MISO, FERC Electric Tariff, Module C, Energy and
Operating Reserve Markets 39.2.1B (34.0.0) (``All Regulation
Qualified Resources in the Day-Ahead Energy and Operating Reserve
Market must be capable of automatically responding to and
alleviating frequency deviations through a speed governor or similar
device in accordance with the Applicable Reliability Standards.'').
\47\ CAISO, 156 FERC ] 61,182, at PP 10-12 and 17 (2016).
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E. Notice of Inquiry
1. Summary
21. On February 18, 2016, the Commission issued the NOI to explore
issues regarding essential reliability
[[Page 85180]]
services and the evolving Bulk-Power System.\48\ In particular, the
Commission asked a broad range of questions on the need for reform of
its rules and regulations regarding the provision of and compensation
for primary frequency response. The Commission explained that there is
a significant risk that, as conventional synchronous generating
facilities retire or are displaced by increased numbers of VERs that do
not typically contribute to system inertia or have primary frequency
response capabilities, the net amount of frequency responsive
generation online will be reduced.\49\ The Commission also explained
that these developments and their potential impacts could challenge
system operators in maintaining reliability.\50\ Further, the
Commission explained that NERC Reliability Standard BAL-003-1.1 and the
pro forma LGIA and pro forma SGIA do not specifically address a
generator's ability to provide frequency response.\51\ The Commission
noted, however, that while in previous years many non-synchronous
generating facilities were not designed with primary frequency response
capabilities, the technology now exists for new non-synchronous
generating facilities to install primary frequency response
capability.\52\
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\48\ NOI, 154 FERC ] 61,117.
\49\ Id. P 12.
\50\ Id. P 14.
\51\ Id. P 41.
\52\ Id. P 43.
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22. Accordingly, the Commission requested comments on three main
sets of issues. First, the Commission sought comment on whether
amendments to the pro forma LGIA and pro forma SGIA are warranted to
require all new generating facilities, both synchronous and non-
synchronous, to have primary frequency response capabilities as a
precondition of interconnection.\53\ Second, the Commission sought
comment on the performance of existing generating facilities and
whether primary frequency response requirements for these facilities
are warranted.\54\ Finally, the Commission sought comment on
compensation for primary frequency response.\55\
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\53\ Id. PP 2 and 44-45.
\54\ Id. PP 2, 46, and 52.
\55\ Id. PP 2, 53-54.
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2. Comments on Modifying the Pro Forma LGIA and Pro Forma SGIA
23. The Commission received a robust response from industry, with
47 entities collectively submitting nearly 700 pages of comments that
provided responses to some or all of the questions posed by the
NOI.\56\ Relevant to the proposed revisions considered in this NOPR,
the Commission received numerous comments on whether the pro forma LGIA
and pro forma SGIA should be revised to include requirements for all
newly interconnecting generating facilities, whether synchronous or
non-synchronous, to install primary frequency response capability.\57\
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\56\ The Appendix lists the entities that submitted comments and
the shortened names that are used throughout this NOPR.
\57\ NOI, 154 FERC ] 61,117 at P 45.
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a. Comments in Support of Modifying the pro forma LGIA and pro forma
SGIA
24. Most commenters support, or are not opposed to, revising the
pro forma LGIA and SGIA to impose primary frequency response capability
requirements on all new generating facilities as suggested in the
NOI.\58\ Several commenters indicate that the nation's changing
resource mix could create reliability concerns related to the provision
of primary frequency response. For example, PJM Utilities Coalition
states that while newer generating facilities are not installing
frequency response capability, the existing generating facilities that
do provide this essential reliability service have more limited
capability, due to the cost of operation and planned retirements,
placing the grid at further risk.\59\ Peak Reliability, the reliability
coordinator for the Western Interconnection, states that as baseload
generation retires, the number of generators providing primary
frequency response is reduced and may present reliability challenges
for system operators, as fewer options are available to reduce
frequency deviations following an unexpected loss of generation or
load.\60\ CAISO asserts that due to the increased proportion of
renewable generating facilities operating in CAISO's balancing
authority area, there may not be sufficient frequency responsive
capacity online when the system has high renewable output and low load
levels.\61\ Bonneville states that the trend of declining frequency
response capability will continue with a changing resource mix, unless
provisions are put in place to assure that adequate inertial and
primary frequency response capability are available in the future.\62\
NERC states that the rapidly changing resource mix may reduce the level
of available frequency capability.\63\
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\58\ APPA, et al. Comments at 6; Bonneville Comments at 6; CAISO
Comments at 2; California Cities Comments at 2; ELCON Comments at 5;
EEI Comments at 12; EPSA, et al. Comments at 8; Howard F. Illian
Comments at 43; Idaho Power Comments at 1; IEEE-PES Comments at 1;
Indicated ISOs/RTOs Comments at 3; ITC, et al. Comments at 1; MISO
Comments at 4; MISO TOs Comments at 6; NARUC Comments at 3; NERC
Comments at 17; North American Generator Forum Comments at 2; Peak
Reliability Comments at 4; PG&E Comments at 2; SoCal Edison Comments
at 4; Southern Company Comments at 2; Tri-State Generation Comments
at 3; WIRAB Comments at 3.
\59\ PJM Utilities Coalition Comments at 3.
\60\ Peak Reliability Comments at 4.
\61\ CAISO Comments at 2.
\62\ Bonneville Comments at 2.
\63\ NERC Comments at 17.
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25. Numerous commenters assert that they recognize the benefits of
revising the pro forma LGIA and pro forma SGIA to require primary
frequency response capabilities for new generators. NERC, for example,
asserts that new primary frequency response requirements for generators
will improve operator flexibility for system restoration and island
capability and help balancing authorities meet their frequency response
obligations.\64\ NERC also asserts that revisions to the pro forma LGIA
and pro forma SGIA would result in measurable, clear requirements
applicable to all new generating facilities in a fair and equitable
manner.\65\ NERC points out, however, that primary frequency response
capability, by itself, would not require a resource to respond if
called upon to help a balancing authority meet its frequency response
obligation, and that, as a result, it is important to have mechanisms
to ensure that sufficient frequency response capability is not only
available but ready to respond at all times.\66\ CASIO, Indicated ISOs/
RTOs, MISO, and a number of trade associations also support
modifications to the pro forma LGIA and pro forma SGIA for new
generating facilities to install primary frequency response
capability.\67\ PJM Utilities Coalition states that, with all new
generating facilities (both synchronous and non-synchronous) being
fully capable of providing primary frequency response, requiring this
capability will ensure that system operators have the ability to
reliably operate the grid of the future.\68\ Peak Reliability states
that it supports modifications to the pro forma LGIA and pro forma SGIA
and that requiring generating facilities to install or provide
frequency response in the initial stages of the interconnection process
will ensure that the grid is able to maintain
[[Page 85181]]
this essential service even as the resource mix changes.\69\
---------------------------------------------------------------------------
\64\ Id.
\65\ Id.
\66\ Id. at 18.
\67\ APPA, et al. Comments at 2; CAISO Comments at 2; EEI
Comments at 3; EPSA, et al. Comments at 8; Indicated ISOs/RTOs
Comments at 3; MISO Comments at 4; North American Generator Forum
Comments at 2.
\68\ PJM Utilities Coalition Comments at 4-5.
\69\ Peak Reliability Comments at 4-5.
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26. Other commenters also express support for revising the pro
forma LGIA and pro forma SGIA. Bonneville points out that selling
primary frequency response capability would not provide sufficient
incentive for new generating facilities to invest in such capability,
and argues that the only way to ensure that there is enough primary
frequency response capability is to require new generators to install
it.\70\ WIRAB advises that while current studies do not indicate that
there is a shortage of primary frequency response in the Western
Interconnection and that all generators do not need to provide primary
frequency response all of the time, the Commission should, however,
require that all new generator owners install primary frequency
response capability because of the changing resource mix in the Western
Interconnection and the associated uncertainty regarding the future
provision of primary frequency response.\71\
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\70\ Bonneville Comments at 21.
\71\ WIRAB Comments at 5-6.
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27. Several commenters that generally support revising the pro
forma LGIA and pro forma SGIA also express certain concerns. For
example, Southern Company expresses support for revising the pro forma
LGIA and pro forma SGIA, but caveats its support by arguing that new
regulations for primary frequency response should include an ``opt-
out'' provision that would allow balancing authorities that do not
anticipate frequency response shortfalls to delay the implementation of
the new pro forma LGIA and pro forma SGIA requirements until these
needs are actually anticipated in their regions in order to avoid
higher costs.\72\ EPSA, et al. state that while they do not fully
oppose amending the pro forma LGIA and pro forma SGIA, they recommend
that the Commission explore more effective and cost efficient ways to
address the range of issues posed in the NOI and consider a measured
approach before mandating governors for all prospective interconnecting
generation.\73\
---------------------------------------------------------------------------
\72\ Southern Company Comments at 2-3.
\73\ EPSA, et al. Comments at 8-9.
---------------------------------------------------------------------------
28. Some commenters that support modifying the pro forma LGIA and
pro forma SGIA also assert that the costs of implementing primary
frequency response capability for new generating facilities are
low.\74\ For example, APPA, et al. state that the capability for
providing primary frequency response is almost always installed in
synchronous generation, and that the inclusion of this additional
control for new non-synchronous generating facilities would likely add
only nominal costs.\75\ EEI asserts that all new generating facilities
coming online can be fully capable of providing primary frequency
response and that the associated cost of installing such capability
during initial manufacturing or construction of a new VER is small when
considering the overall cost of the new generating facility.\76\
---------------------------------------------------------------------------
\74\ APPA, et al. Comments at 6; Bonneville Comments at 8;
California Cities Comments at 2; EEI Comments at 13; Indicated ISOs/
RTOs Comments at 5; MISO Comments at 4; SoCal Edison Comments at 2.
\75\ APPA, et al. Comments at 6.
\76\ EEI Comments at 13.
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29. In contrast to new generating facilities, some entities,
however, explain that the costs of retrofitting existing generating
facilities with primary frequency response capability could be
significant in some cases.\77\ For example, WIRAB states that the high
cost of retrofitting existing generators to install the necessary
control equipment supports limiting the requirement to new generators
and taking early action now.\78\
---------------------------------------------------------------------------
\77\ APPA, et al. Comments at 6; Bonneville Comments at 8;
California Cities Comments at 8; EEI Comments at 14; Idaho Power
Comments at 4; WIRAB Comments at 6.
\78\ WIRAB Comments at 6.
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30. In regards to nuclear generating facilities, some commenters
indicate that nuclear plants have separate licensing requirements under
the Nuclear Regulatory Commission and should not be required to provide
primary frequency response. For example, the Nuclear Energy Institute
asserts that while nearly all new generating facilities should be able
to provide primary frequency response, nuclear plants are not well-
suited to provide primary frequency response due to restrictions by
their operating licenses issued by the Nuclear Regulatory
Commission.\79\ The Nuclear Energy Institute also asserts that turbine
controls on most nuclear units are designed to maintain the internal
steam pressure and are not intended to react to changes in the
grid.\80\ Similarly, the MISO TOs assert that requiring nuclear units
to have primary frequency response capability would be contrary to
Nuclear Regulatory Commission licensing requirements, and could have a
detrimental effect on the safety of the nuclear fleet.\81\
---------------------------------------------------------------------------
\79\ Nuclear Energy Institute Comments at 1 and 4.
\80\ Nuclear Energy Institute Comments at 4.
\81\ MISO TOs Comments at 7.
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31. In the NOI, the Commission also sought comment on whether it
would be appropriate to include recommended governor settings contained
within NERC's Primary Frequency Control Guideline in the pro forma LGIA
and pro forma SGIA.\82\ Numerous commenters express support for
including NERC's recommended governor control settings in the pro forma
LGIA and pro forma SGIA.\83\ Some commenters note that NERC's Guideline
is consistent with existing regulations or practices in certain
regions.\84\ Indicated ISOs/RTOs point out that common primary
frequency response settings for generators in an Interconnection will
enhance reliability by reducing maneuvering by individual
generators.\85\ MISO asserts that NERC's Guideline provides a sound
baseline.\86\ NERC notes that its Guideline was developed by technical
committees with expertise and judgment of the electric industry, and
accordingly, the Guideline is the ``most advanced set of nation-wide
best practices and information currently available to support frequency
response capability.'' \87\
---------------------------------------------------------------------------
\82\ NOI, 154 FERC ] 61,117 at P 45.
\83\ See e.g., Bonneville Comments at 7; IEEE-PES Comments at 1;
Indicated ISOs/RTOs Comments at 4; California Cities Comments at 2;
WIRAB Comments at 7.
\84\ Indicated ISOs/RTOs Comments at 4; SoCal Edison Comments at
4; Peak Reliability Comments at 7; Manitoba Comments at 8.
\85\ Indicated ISOs/RTOs Comments at 5.
\86\ MISO Comments at 4.
\87\ NERC Comments at 12.
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32. However, not all entities that support modifying the pro forma
LGIA and pro forma SGIA endorse the inclusion of NERC's recommended
governor settings. For example, EEI states that it does not support
including prescriptive performance requirements for governor control
settings or other performance indicators in the pro forma LGIA or pro
forma SGIA due to the physical, technical, or operational limitations
of new generating facilities to provide primary frequency response.\88\
Similarly, APPA, et al. state that they do not support revising the pro
forma LGIA and pro forma SGIA to include the recommended settings
contained within NERC's Guideline at this time.\89\ MISO TOs state that
some transmission owners in MISO believe that NERC's recommended
governor settings are appropriate for traditional synchronous
generating facilities, but recommend additional consideration for other
generation technologies.\90\ On the other hand, MISO TOs state that
other transmission owners in MISO request
[[Page 85182]]
flexibility and assert that specified governor settings should not be
``hard-wired'' or dictated in the pro forma LGIA and pro forma
SGIA.\91\
---------------------------------------------------------------------------
\88\ EEI Comments at 15-17.
\89\ APPA, et al. Comments at 8.
\90\ MISO TOs Comments at 8.
\91\ MISO TOs Comments at 8.
---------------------------------------------------------------------------
b. Comments Opposed To Modifying the pro forma LGIA and pro forma SGIA
33. Other commenters contend that the pro forma LGIA and pro forma
SGIA should not be modified to require primary frequency response
capability from new generating facilities.\92\ Some commenters argue
that requiring all new generating facilities to have primary frequency
response capability will result in extra costs above those necessary to
ensure reliability.\93\ For example, APS argues that a global mandate
to provide primary frequency response or to require generating
facilities to be primary frequency response capable would result in
significantly increased costs while providing a disproportionately
minor impact on improving reliability.\94\ Powerex asserts that
modifying the pro forma LGIA and pro forma SGIA to include minimum
primary frequency response requirements will increase the cost of entry
for new generators, particularly VERs, which typically are not designed
with such capability.\95\ Several commenters note that there would be a
significant opportunity cost for certain generating facilities to
reserve headroom for the provision of primary frequency response.\96\
---------------------------------------------------------------------------
\92\ AES Companies Comments at 6; Apex Comments at 6; APS
Comments at 6; AWEA Comments at 12; Chelan County Comments at 2; ESA
Comments at 2; Grid Storage Consulting Comments at 2; Microgrids
Resources Coalition Comments at 3; NRECA Comments at 9; Powerex
Comments at 5; SDG&E Comments at 3; SolarCity Comments at 1; TVA
Comments at 2.
\93\ Apex Comments at 5-6; APS Comments at 6; AWEA Comments at
12; Chelan County Comments at 2; Powerex Comments at 5; Solar City
Comments at 1.
\94\ APS Comments at 6. It is unclear whether the increased
costs referenced by APS refer only to the costs for the necessary
equipment to provide primary frequency response or the costs
associated with maintaining the headroom necessary to provide
primary frequency response.
\95\ Powerex Comments at 5.
\96\ Apex Comments at 7; Solar City Comments at 1; AWEA Comments
at 6.
---------------------------------------------------------------------------
34. Some of the commenters that are opposed to modifying the pro
forma LGIA and pro forma SGIA assert that they prefer a market-based
approach instead of a requirement for new generating facilities to
install primary frequency response capability.\97\ For example, AWEA
asserts that, initially, the pro forma LGIA and pro forma SGIA should
not be revised to require new generating facilities to have primary
frequency response capability, and only if market-based steps do not
satisfactorily address the need for primary frequency response, then
the Commission could consider an additional requirement for new
generating facilities to have such capability as a final step.\98\
---------------------------------------------------------------------------
\97\ Apex Comments at 6; AWEA Comments at 12; Chelan County
Comments at 2; ESA Comments at 2; SDG&E Comments at 3.
\98\ AWEA Comments at 12.
---------------------------------------------------------------------------
35. Other commenters oppose mandatory requirements and prefer a
voluntary approach to improving primary frequency response
performance.\99\ For example, TVA asserts that if current voluntary
actions fail to show improvement in primary frequency response, then
the pro forma LGIA and pro forma SGIA could be revised to contain a
general primary frequency response requirement, similar to reactive
power, but that NERC should be directed to establish governor settings
and performance requirements through the NERC Standards Development
Process instead of the Commission including such requirements in the
pro forma LGIA and pro forma SGIA.\100\ Some commenters assert that
governor control details are better left to individual balancing
authorities.\101\ For example, APS argues that the Commission should
allow balancing authorities to determine the type and magnitude of
generating facilities within its balancing authority area that are
frequency-response enabled.\102\ APS also points out that any need to
install frequency response capability or otherwise support frequency
response performance can and should be evaluated and agreed upon
between a generating facility and the transmission provider during the
interconnection study process.\103\
---------------------------------------------------------------------------
\99\ APS Comments at 8; NRECA Comments at 6; TVA Comments at 2.
\100\ TVA Comments at 2-3 and 5.
\101\ APS Comments at 8; AES Companies Comments at 8.
\102\ APS Comments at 8.
\103\ Id. at 15.
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II. Discussion
A. Primary Frequency Response Requirements
1. The Need for Reform
36. Pursuant to FPA section 206, the Commission preliminarily finds
that conditions have changed since the issuance of Order Nos. 2003 and
2006 and certain aspects of the pro forma LGIA and pro forma SGIA may
now be unjust, unreasonable, unduly discriminatory, or
preferential.\104\ Specifically, as discussed above, the record
indicates that while the frequency response performance of the Eastern
and Western Interconnections is currently adequate, the frequency
response performance of both Interconnections has significantly
declined from historic values.\105\ Furthermore, the record shows that
there is an ongoing evolution of the nation's generation resource mix,
including significant retirements of baseload generation and an
increasing proportion of VERs interconnecting to the electric
grid.\106\ Several commenters point out that there is significant risk
that the rapidly changing resource mix may reduce the level of
available frequency response capability online.\107\ This is in part
because, as noted in the NOI, VERs have not been consistently designed
with primary frequency response capabilities.\108\ The record suggests,
however, that VER manufacturers have made significant technological
advancements in recent years to develop primary frequency response
capability for VERs.\109\ In addition, NERC, in conjunction with
various industry stakeholders, has developed more robust technical
guidance for the operation of governors or equivalent controls.\110\ As
a result of the evolving resource mix and the potential for adverse
impacts on primary frequency response, the Commission is concerned that
there may be potential reliability impacts if it does not undertake the
reforms proposed in this NOPR. Moreover, the Commission is concerned
that certain aspects of the existing pro forma LGIA and pro forma SGIA
may no longer be just and reasonable.
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\104\ The Commission routinely evaluates the effectiveness of
its regulations and policies in light of changing industry
conditions to determine if changes are necessary. See, e.g., Order
No. 764, FERC Stats. & Regs. ] 31,331.
\105\ See NERC 2015 Frequency Response Webinar at 10, NERC
Frequency Response Initiative Report at 22, and LBNL 2010 Report at
pp xiv-xv.
\106\ See, e.g., P 12, supra (describing recent and ongoing
changes in the nation's generation mix).
\107\ See, e.g., Bonneville Comments at 2; CAISO Comments at 2;
NERC Comments at 17; Peak Reliability Comments at 4; PJM Utilities
Coalition Comments at 3.
\108\ NOI, 154 FERC ] 61,117 at PP 42-43.
\109\ See, e.g., PJM Utilities Comments at 4-5; EEI Comments at
13. See also PJM Interconnection, L.L.C., Docket No. ER15-1193-000
(March 6, 2015) Transmittal Letter at 11. See also NERC 2014 LTRA,
at 27 (Nov. 2014), https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2014LTRA_ERATTA.pdf.
\110\ See P 16, supra.
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37. First, the current requirements for governor controls in the
pro forma LGIA do not reflect advances in technology or the latest
recommended operating practices. Specifically, current Article 9.6.2.1
states that ``speed governors,'' if installed, must be operated in
automatic
[[Page 85183]]
mode. However, many of the new generating facilities interconnecting to
the grid, such as wind and solar, do not utilize traditional speed
governors; instead they utilize enhanced inverters and other plant
supervisory control technology that can be designed to include primary
frequency response capability.\111\ Therefore, due to advancements in
technology, the Commission preliminarily finds that the existing
references to ``speed governors'' in Article 9.6.2.1 that apply only to
synchronous resources are outdated, and therefore may no longer be just
and reasonable.
---------------------------------------------------------------------------
\111\ See Electric Power Research Institute, Recommended
Settings for Voltage and Frequency Ride Through of Distributed
Energy Resources (May 2015) at 27, https://www.epri.com/abstracts/Pages/ProductAbstract.aspx?ProductId=000000003002006203. See also
National Renewable Energy Labs (NREL), Advanced Grid-Friendly
Controls Demonstration Project for Utility-Scale PV Power Plants, at
1-2 (Jan. 2016), https://www.nrel.gov/docs/fy16osti/65368.pdf.
---------------------------------------------------------------------------
38. Second, since the issuance of Order No. 2003 and the
establishment of the pro forma LGIA, NERC, in conjunction with industry
stakeholders, has amassed a significant body of knowledge in regards to
the operation of generator governors and plant control systems. For
example, as noted above, NERC observed in 2012 that a number of
generators implemented deadband settings that were so wide as to
effectively defeat the ability to provide primary frequency response,
and that many generators provide frequency response in the wrong
direction during a disturbance.\112\ Additionally, as noted above, NERC
observed in 2015 that in many conventional steam plants, deadband
settings exceed a 0.036 Hz dead band, resulting in primary
frequency response that is not sustained, and that the vast majority of
the gas turbine fleet is not frequency responsive.\113\
---------------------------------------------------------------------------
\112\ See P 16, supra.
\113\ Id.
---------------------------------------------------------------------------
39. The record here suggests that the actual governor and plant
control system settings that are being implemented by some generator
owners and/or operators may be defeating the intent of Article 9.6.2.1
of the pro forma LGIA. In response to these issues, NERC, through the
work of its various task forces, subcommittees, and initiatives, has
developed a voluntary Guideline that includes recommended droop and
deadband settings based on significant investigation.\114\ However, the
pro forma LGIA does not currently reflect these updated recommended
practices for governor and plant control system settings of generating
facilities.
---------------------------------------------------------------------------
\114\ See NERC Primary Frequency Control Guideline.
---------------------------------------------------------------------------
40. Third, given the nation's evolving resource mix and the
potential adverse impacts on primary frequency response as noted in the
NOI and pointed out by several commenters, the Commission believes that
changes to the pro forma LGIA and pro forma SGIA may be necessary to
provide for the continued reliable operation of the power system. As
noted above, the Task Force concluded that all new generating
facilities should be required to be capable of providing primary
frequency response.\115\ However, the pro forma LGIA does not currently
require large generating facilities to install such capability; rather,
it only requires governor operation in ``automatic mode'' if a ``speed
governor'' is installed.\116\
---------------------------------------------------------------------------
\115\ See P 15, supra.
\116\ Article 9.6.2.1 of the pro forma LGIA.
---------------------------------------------------------------------------
41. In addition, the Commission is concerned that the current pro
forma SGIA may be unduly discriminatory or preferential because it does
not establish any specific requirements with respect to the
installation or operation of governors or equivalent frequency control
equipment. In particular, the pro forma SGIA does not have a similar
provision to Article 9.6.2.1 of the pro forma LGIA. The Commission has
previously acted under FPA section 206 to remove inconsistencies
between the pro forma LGIA and pro forma SGIA when there is no economic
or technical basis for treating large and small generating facilities
differently.\117\ Similarly, in this instance, the record developed
from the NOI appears to suggest that small generating facilities are
capable of installing and enabling governors at low cost in a manner
comparable to large generating facilities.\118\ As discussed above, the
record indicates that there have been significant advances in
technology, as well as the development of more robust technical
guidance for the operation of governors or equivalent controls for both
large and small generating facilities.\119\ In particular, the IEEE-
P1547 Working Group noted that its new IEEE-1547 standard for
interconnecting distributed generation will likely include certain
requirements for providing primary frequency response.\120\ Given these
low-cost technological advances, the Commission does not anticipate
that these additional requirements added in the pro forma SGIA will
present a barrier to entry for small generating facilities. And, given
the need for additional primary frequency response capability and an
increasingly large market penetration of small generating facilities,
the Commission believes that there is a need to add these requirements
to the pro forma SGIA to help ensure adequate primary frequency
response capability.
---------------------------------------------------------------------------
\117\ See Requirements for Frequency and Voltage Ride Through
Capability of Small Generating Facilities, Order No. 828, 81 FR
50,290 (Aug. 1, 2016), 156 FERC ] 61,062 (2016), (The Final Rule
revised the pro forma SGIA such that small generating facilities
have frequency and voltage ride through requirements comparable to
large generating facilities).
\118\ IEEE-P1547 Working Group Comments at 1, 5, and 7.
Moreover, the Commission notes that other commenters stated costs of
installing primary frequency response capability are generally low,
but did not differentiate between small and large generating
facilities. See, e.g., APPA, et al. Comments at 6; California Cities
Comments at 2; EEI Comments at 13; Indicated ISOs/RTOs Comments at
3-5; SoCal Edison Comments at 2.
\119\ See PP 13, 36, supra.
\120\ IEEE-P1547 Working Group Comments at 1, 5, and 7.
---------------------------------------------------------------------------
42. Moreover, as noted above, a number of commenters assert that
costs for new generating facilities to install the capability of
providing primary frequency response are low, suggesting that there is
not a financial barrier to small generating facilities installing the
capability to provide frequency response.\121\ PJM's recent changes to
require both small and large non-synchronous generating facilities to
use enhanced inverters, which include primary frequency response
capability, among other functions, further support this notion.\122\
---------------------------------------------------------------------------
\121\ See, e.g., APPA, et al. Comments at 2; EEI Comments at 13;
Indicated ISOs/RTOs Comments at 5; SoCal Edison Comments at 2.
\122\ PJM Interconnection, L.L.C., 151 FERC ] 61,097 at P 28
(the Commission stated that it ``find[s] that PJM's proposal will
not present a barrier to non-synchronous resources.'').
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2. Commission Proposal
43. To remedy the potentially unjust, unreasonable, and unduly
discriminatory or preferential practices described above, the
Commission preliminarily finds that revisions to the pro forma LGIA and
pro forma SGIA are appropriate. The Commission believes that revising
the pro forma LGIA and pro forma SGIA to require all new generating
facilities to install, maintain, and operate a functioning governor or
equivalent controls, consistent with the proposed requirements
described below, will help to ensure adequate primary frequency
response capability as the resource mix continues to evolve, ensure
fair and consistent treatment for all types of generating facilities,
help balancing authorities meet their frequency response obligations
pursuant to NERC Reliability Standard BAL-003-1.1, and help improve
reliability during
[[Page 85184]]
system restoration and islanding situations.\123\
---------------------------------------------------------------------------
\123\ See NERC Comments at 17. See also NERC Essential
Reliability Services Task Force Measures Framework Report at iv.
---------------------------------------------------------------------------
44. In particular, the Commission proposes to revise the pro forma
LGIA and pro forma SGIA to include the following: (1) Requirements for
new large and small generating facilities, both synchronous and non-
synchronous, to install, maintain, and operate equipment capable of
providing primary frequency response as a condition of interconnection;
(2) requirements for governor or equivalent controls to be operated, at
a minimum, with maximum 5 percent droop and 0.036 Hz
deadband settings; (3) requirements to ensure the timely and sustained
response to frequency deviations, including provisions to prevent
plant-level (i.e., outer-loop) control equipment from inhibiting
primary frequency response and resulting in premature withdrawal; and
(4) a requirement for droop parameters to be based on nameplate
capability with a linear operating range of 59 to 61 Hz. Additionally,
as informed by NOI commenters, the Commission believes that it is not
necessary to impose a generic headroom requirement or subject newly
interconnecting nuclear generating facilities to the new requirements.
The Commission does not propose to mandate any separate compensation
related to the proposed requirements. The Commission seeks comment on
the proposed reforms, as discussed more fully below.
45. Specifically, the Commission proposes to revise existing
sections 9.6 and 9.6.2.1 of the pro forma LGIA and to include proposed
new sections 9.6.4, 9.6.4.1, 9.6.4.2, and 9.6.4.3. Similarly, the
Commission proposes to revise existing section 1.8 of the pro forma
SGIA and add proposed new sections 1.8.4, 1.8.4.1, 1.8.4.1.1,
1.8.4.1.2, and 1.8.4.1.3.\124\
---------------------------------------------------------------------------
\124\ The specific proposed modifications and additions to the
pro forma LGIA and pro forma SGIA are set forth at PP 52-53, below.
---------------------------------------------------------------------------
46. The Commission's proposed revisions to the pro forma LGIA and
pro forma SGIA would apply to new generating facilities that execute or
request the unexecuted filing of interconnection agreements on or after
the effective date of any Final Rule issued in Docket No. RM16-6-000.
The Commission also proposes to apply the requirements to any large or
small generating facility that has an executed or has requested the
filing of an unexecuted LGIA or SGIA as of the effective date of any
Final Rule in Docket No. RM16-6-000, but that takes any action that
requires the submission of a new interconnection request that results
in the filing of an executed or unexecuted interconnection agreement on
or after the effective date of any Final Rule in Docket No. RM16-6-000.
47. In particular, the proposed revisions to the pro forma LGIA and
pro forma SGIA would require new large and small generating facilities
to install, maintain, and operate a functioning governor or equivalent
controls, which the Commission proposes to define as the required
hardware and/or software that provides frequency responsive real power
control with the ability to sense changes in system frequency and
autonomously adjust the generating facility's real power output in
accordance with the proposed maximum droop and deadband parameters and
in the direction needed to correct frequency deviations. The Commission
seeks comment on this proposal.
48. The Commission also proposes to require new large and small
generating facilities to install, maintain and operate governor or
equivalent controls with the ability to operate with a maximum 5
percent droop and 0.036 Hz deadband parameter, consistent
with NERC's recommended guidance. As noted above, the Commission sought
comment in the NOI on whether NERC's recommended guidance for governor
settings related to droop and deadband should be included in the pro
forma LGIA and pro forma SGIA, and numerous commenters agreed stating
that NERC's Guideline provides a sound baseline.\125\ Therefore, the
Commission preliminarily finds that a maximum droop setting of 5
percent and deadband setting of 0.036 Hz are appropriate to
include in the pro forma LGIA and pro forma SGIA as interconnection
requirements for new generating facilities. The Commission notes that
these proposed requirements are minimum requirements; therefore, if a
new generating facility elects, in coordination with its transmission
provider, to operate in a more responsive mode by using lower droop or
tighter deadband settings, nothing in these requirements would prohibit
it from doing so.\126\ The Commission seeks comment on these proposed
requirements for droop and deadband settings.
---------------------------------------------------------------------------
\125\ See e.g., Bonneville Comments at 7; California Cities
Comments at 2; IEEE-PES Comments at 2; Indicated ISOs/RTOs Comments
at 4; MISO Comments at 4; WIRAB Comments at 7.
\126\ Moreover, the Commission proposes that nothing in these
requirements would prohibit the implementation of asymmetrical droop
settings (i.e., different droop settings for under-frequency and
over-frequency conditions), provided that each segment has a droop
value of no more than 5 percent.
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49. The Commission also proposes to prohibit all new large and
small generating facilities from taking any action that would inhibit
the provision of primary frequency response, except under certain
conditions as discussed below. The lack of coordination between
governor and plant-level control systems can result in premature
withdrawal of primary frequency response by allowing additional plant
control systems to reverse the action of the governor to return the
unit to operating at a pre-selected target set-point.\127\ NERC's
Guideline explains that ``in order to provide sustained primary
frequency response, it is essential that the prime mover governor,
plant controls and remote plant controls are coordinated.'' \128\
Accordingly, the Commission proposes to require new generating
facilities that respond to frequency deviations to not inhibit primary
frequency response, such as by coordinating plant-level, outer-loop
control equipment with the governor or equivalent controls, except
under certain operational constraints including, but not limited to,
ambient temperature limitations, outages of mechanical equipment, or
regulatory requirements. The Commission also proposes to require new
generating facilities to respond to frequency deviations without undue
delay and to sustain the response until at least system frequency
returns to a stable value within the governor's deadband setting. The
Commission believes this proposed requirement for sustained response is
consistent with the current requirements of PJM and ISO-NE as well as
similar OATT revisions recently implemented by CAISO.\129\ The
Commission seeks comment on the proposed requirements for sustained
response. In particular, the Commission seeks comment on whether these
provisions will be sufficient to prevent plant-level (i.e., outer-loop)
controls from inhibiting primary frequency response.
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\127\ NERC Frequency Response Initiative Report at 31. See also
NOI, 154 FERC ] 61,117 at P 49 (stating that primary frequency
response withdrawal ``has the potential to degrade the overall
response of the Interconnection and result in a frequency that
declines below the original nadir'').
\128\ NERC Primary Frequency Control Guideline at 4.
\129\ See, e.g., ISO-NE Operating Procedure OP-14 and PJM Manual
14D. See also CAISO, 156 FERC ] 61,182 at PP 10-12 and 17.
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50. Regarding droop settings, in its comments to the NOI, MISO
proposed that a linear droop should be available between 59 to 61
Hz.\130\ The
[[Page 85185]]
Commission believes that this is reasonable because it would allow for
new generating facilities that remain connected during frequency
deviations to provide a proportional response within this range of
frequencies. Accordingly, the Commission proposes to require the droop
parameter to be based on the nameplate capability of the unit and
linear in operating range between 59 to 61 Hz. The Commission seeks
comment on these proposed requirements for droop settings.
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\130\ MISO Comments at 4.
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51. Several NOI commenters expressed concern about possible generic
headroom requirements \131\ that could result in significant
opportunity costs.\132\ The Commission clarifies that nothing in these
proposed reforms will impose a generic headroom requirement for new
generating facilities or affect the unit commitment and dispatch
decisions of balancing authorities. Therefore, if a generating facility
that is subject to these proposed requirements has been dispatched by
its balancing authority to a set-point at which there is no available
operating range to increase or decrease its output in response to
frequency deviations, it would not be in violation of the proposed
requirements in regards to providing sustained response. The Commission
believes that the reliability benefits from the proposed modifications
to the pro forma LGIA and pro forma SGIA do not require imposing
additional costs that would result from a generic headroom requirement.
The Commission also agrees with NOI commenters regarding the unique
operating characteristics and regulatory requirements of nuclear
generating facilities regulated by the Nuclear Regulatory Commission,
and therefore proposes to exempt such generating facilities from the
proposed reforms.\133\ The Commission seeks comment on the proposal to
not impose a generic headroom requirement and to not apply the new
requirements to nuclear generating facilities.
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\131\ A generic headroom requirement would require generating
facilities to operate below maximum output at all times to ensure
sufficient ability to increase their real power output in response
to under-frequency conditions.
\132\ See, e.g., Apex Comments at 7; Solar City Comments at 1;
AWEA Comments at 6.
\133\ See, e.g., Nuclear Energy Institute Comments at 1, 4; MISO
TOs Comments at 7.
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52. In light of the above discussion, the Commission proposes to
modify sections 9.6 and 9.6.2.1 of the pro forma LGIA and add new
sections 9.6.4, 9.6.4.1, 9.6.4.2, and 9.6.4.3 as follows:
9.6 Reactive Power and Primary Frequency Response
9.6.2.1 Voltage Regulators. Whenever the Large Generating
Facility is operated in parallel with the Transmission System and
voltage regulators are capable of operation, Interconnection
Customer shall operate the Large Generating Facility with its
voltage regulators in automatic operation. If the Large Generating
Facility's voltage regulators are not capable of such automatic
operation, Interconnection Customer shall immediately notify
Transmission Provider's system operator, or its designated
representative, and ensure that such Large Generating Facility's
reactive power production or absorption (measured in MVARs) are
within the design capability of the Large Generating Facility's
generating unit(s) and steady state stability limits.
Interconnection Customer shall not cause its Large Generating
Facility to disconnect automatically or instantaneously from the
Transmission System or trip any generating unit comprising the Large
Generating Facility for an under or over frequency condition unless
the abnormal frequency condition persists for a time period beyond
the limits set forth in ANSI/IEEE Standard C37.106, or such other
standard as applied to other generators in the Control Area on a
comparable basis.
9.6.4 Primary Frequency Response. Interconnection Customer shall
ensure the primary frequency response capability of its Large
Generating Facility by installing, maintaining, and operating a
functioning governor or equivalent controls. The term ``functioning
governor or equivalent controls'' as used herein shall mean the
required hardware and/or software that provides frequency responsive
real power control with the ability to sense changes in system
frequency and autonomously adjust the Large Generating Facility's
real power output in accordance with the droop and deadband
parameters and in the direction needed to correct frequency
deviations. Interconnection Customer is required to install a
governor or equivalent controls with the capability of operating
with a maximum 5 percent droop and 0.036 Hz
deadband. The droop characteristic shall be based on the nameplate
capacity of the Large Generating Facility, and shall be linear in
the range of 59 to 61 Hz. The deadband parameter shall be the range
of frequencies above and below nominal (60 Hz) in which the governor
or equivalent controls is not expected to adjust the Large
Generating Facility's real power output in response to frequency
deviations. Interconnection Customer shall notify Transmission
Provider that the primary frequency response capability of the Large
Generating Facility has been tested and confirmed during
commissioning. Once Interconnection Customer has synchronized the
Large Generating Facility with the Transmission System,
Interconnection Customer shall operate the Large Generating Facility
consistent with provisions specified in Sections 9.6.4.1 and 9.6.4.2
of this Agreement. The primary frequency response requirements
contained herein shall apply to both synchronous and non-synchronous
Large Generating Facilities. Nothing in Sections 9.6.4, 9.6.4.1 and
9.6.4.2 shall require the Large Generating Facility to operate above
its minimum operating limit or below its maximum operating limit, or
otherwise alter its dispatch to have headroom to provide primary
frequency response.
9.6.4.1 Governor or Equivalent Controls. Whenever the Large
Generating Facility is operated in parallel with the Transmission
System, Interconnection Customer shall operate the Large Generating
Facility with its governor or equivalent controls in service and
responsive to frequency. Interconnection Customer shall, in
coordination with Transmission Provider, set the deadband parameter
to a maximum of 0.036 Hz and set the droop
parameter to a maximum of 5 percent. Interconnection Customer shall
be required to provide the status and settings of the governor or
equivalent controls to Transmission Provider upon request. If
Interconnection Customer needs to operate the Large Generating
Facility with its governor or equivalent controls not in service,
Interconnection Customer shall immediately notify Transmission
Provider's system operator, or its designated representative.
Interconnection Customer shall make Reasonable Efforts to return its
governor or equivalent controls into service as soon as practicable.
9.6.4.2 Sustained Response. Interconnection Customer shall
ensure that the Large Generating Facility's real power response to
sustained frequency deviations outside of the deadband setting is
provided without undue delay, and ensure that the response is not
inhibited, except under certain operational constraints including,
but not limited to, ambient temperature limitations, outages of
mechanical equipment, or regulatory requirements. The Large
Generating Facility shall sustain the real power response at least
until system frequency returns to a stable value within the deadband
setting of the governor or equivalent controls.
9.6.4.3 Exemptions. Large Generating Facilities that are
regulated by the United States Nuclear Regulatory Commission shall
be exempt from Sections 9.6.4, 9.6.4.1, and 9.6.4.2 of this
Agreement.
53. Similarly, the Commission proposes to modify section 1.8 of the
pro forma SGIA and add new sections 1.8.4, 1.8.4.1, 1.8.4.2 and 1.8.4.3
as follows:
1.8 Reactive Power and Primary Frequency Response
1.8.4 Primary Frequency Response. Interconnection Customer shall
ensure the primary frequency response capability of its Small
Generating Facility by installing, maintaining, and operating a
functioning governor or equivalent controls. The term ``functioning
governor or equivalent controls'' as used herein shall mean the
required hardware and/or software that provides frequency responsive
real power control with the ability to sense changes in system
frequency and autonomously adjust the Small Generating Facility's
real power output in accordance with the droop and deadband
parameters and in the direction needed to correct frequency
deviations. Interconnection Customer is required to install a
governor or
[[Page 85186]]
equivalent controls with the capability of operating with a maximum
5 percent droop and 0.036 Hz deadband. The droop
characteristic shall be based on the nameplate capacity of the Small
Generating Facility, and shall be linear in the range of 59 to 61
Hz. The deadband parameter shall be the range of frequencies above
and below nominal (60 Hz) in which the governor or equivalent
controls is not expected to adjust the Small Generating Facility's
real power output in response to frequency deviations.
Interconnection Customer shall notify Transmission Provider that the
primary frequency response capability of the Small Generating
Facility has been tested and confirmed during commissioning. Once
Interconnection Customer has synchronized the Small Generating
Facility with the Transmission System, Interconnection Customer
shall operate the Small Generating Facility consistent with the
provisions specified in Sections 1.8.4.1 and 1.8.4.2 of this
Agreement. The primary frequency response requirements contained
herein shall apply to both synchronous and non-synchronous Small
Generating Facilities. Nothing in Sections 1.8.4, 1.8.4.1 and
1.8.4.2 shall require the Small Generating Facility to operate above
its minimum operating limit, below its maximum operating limit, or
otherwise alter its dispatch to have headroom to provide primary
frequency response.
1.8.4.1 Governor or Equivalent Controls. Whenever the Small
Generating Facility is operated in parallel with the Transmission
System, Interconnection Customer shall operate the Small Generating
Facility with its governor or equivalent controls in service and
responsive to frequency. Interconnection Customer shall, in
coordination with Transmission Provider, set the deadband parameter
to a maximum of 0.036 Hz and set the droop
parameter to a maximum of 5 percent. Interconnection Customer shall
be required to provide the status and settings of the governor or
equivalent controls to Transmission Provider upon request. If
Interconnection Customer needs to operate the Small Generating
facility with its governor or equivalent controls not in service,
Interconnection Customer shall immediately notify Transmission
Provider's system operator, or its designated representative.
Interconnection Customer shall make Reasonable Efforts to return its
governor or equivalent controls into service as soon as practicable.
1.8.4.2 Sustained Response. Interconnection Customer shall
ensure that the Small Generating Facility's real power response to
sustained frequency deviations outside of the deadband setting is
provided without undue delay, and ensure that the response is not
inhibited, except under certain operational constraints including,
but not limited to, ambient temperature limitations, outages of
mechanical equipment, or regulatory requirements. The Small
Generating Facility shall sustain the real power response at least
until system frequency returns to a stable value within the deadband
setting of the governor or equivalent controls.
1.8.4.3 Exemptions. Small Generating Facilities that are
regulated by the United States Nuclear Regulatory Commission shall
be exempt from Sections 1.8.4, 1.8.4.1, 1.8.4.2 of this Agreement.
54. The Commission proposes to apply the primary frequency response
requirements to any new large or small generating facility that
executes or requests the unexecuted filing of a LGIA or SGIA on or
after the effective date of any Final Rule issued in this proceeding.
In addition, the Commission proposes to apply the requirements to any
large or small generating facility that has an executed or has
requested the filing of an unexecuted LGIA or SGIA as of the effective
date of any Final Rule in Docket No. RM16-6-000, but that takes any
action that requires the submission of a new interconnection request
that results in the filing of an executed or unexecuted interconnection
agreement on or after the effective date of any Final Rule in Docket
No. RM16-6-000. The Commission seeks comment on the proposed effective
date including whether applying these requirements to existing
generating facilities that take any action that requires the submission
of a new interconnection request that results in the filing of an
executed or unexecuted interconnection agreement on or after the
effective date of any Final Rule in Docket No. RM16-6-000 would be
unduly burdensome.
55. The Commission does not propose in this NOPR to require that
the interconnection customer receive any compensation for these
proposed requirements. The Commission has previously accepted changes
to transmission provider tariffs that similarly required
interconnection customers to install primary frequency response
capability or that established specified governor settings, without
requiring any accompanying compensation.\134\ While the Commission has
not required compensation for similar requirements in the past, it
clarifies that nothing in this NOPR is meant to prohibit a public
utility from filing a proposal for primary frequency response
compensation under FPA section 205, if it so chooses.\135\
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\134\ PJM Interconnection, L.L.C., 151 FERC ] 61,097, at n.58
(2015); CAISO, 156 FERC ] 61,182, at PP 10-12 and 17 (2016); New
England Power Pool, 109 FERC ] 61,155 (2004), order on reh'g, 110
FERC ] 61,335 (2005).
\135\ 16 U.S.C. 824d (2012).
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B. Request for Comment
56. The Commission seeks comment on the proposed: (1) Requirements
for new large and small generating facilities to install, maintain, and
operate a governor or equivalent controls; (2) requirements for droop
and deadband settings of 5 percent and 0.036 Hz,
respectively; (3) requirements for timely and sustained response; (4)
requirement for droop parameters to be based on nameplate capability
with a linear operating range of 59 to 61 Hz; (5) exemptions for new
nuclear units; and (6) effective dates as discussed above. The
Commission also seeks comment on its proposal to not impose a generic
headroom requirement or mandate compensation related to the proposed
reforms.
57. In the NOI, the Commission also sought comment on the
performance of existing resources and whether primary frequency
response requirements for these resources are warranted.\136\ At this
time, the Commission proposes only to adopt the reforms included in
this NOPR regarding newly interconnecting large and small generating
facilities. However, the Commission seeks comment regarding whether the
reforms proposed in this NOPR are sufficient to ensure adequate levels
of primary frequency response, or whether additional reforms are
needed. In particular, the Commission seeks comment on whether
additional primary frequency response performance or capability
requirements for existing resources are needed, and if so, whether the
Commission should impose those requirements by: (1) Directing the
development or modification of a reliability standard pursuant to
section 215(d)(5) of the FPA; or (2) acting pursuant to section 206 of
the FPA to require changes to the pro forma OATT.
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\136\ NOI, 154 FERC ] 61,117 at PP 2, 46-52.
---------------------------------------------------------------------------
C. Proposed Compliance Procedures
58. The Commission proposes to require all public utility
transmission providers to adopt the requirements of any Final Rule in
Docket No. RM16-6-000 as revisions to the LGIA and SGIA in their OATTs
within 60 days after the publication of the Final Rule in the Federal
Register.
59. Some public utility transmission providers may have provisions
in their existing LGIAs and SGIAs that the Commission has found to be
consistent with or superior to the pro forma LGIA and pro forma SGIA.
Where these provisions would be modified by the Final Rule, public
utility transmission providers must either comply with the Final Rule
or demonstrate that these previously-approved variations continue to be
consistent with or superior to the pro forma LGIA and pro forma SGIA as
modified by the Final Rule. The Commission also proposes to permit
appropriate entities to seek
[[Page 85187]]
``independent entity variations'' from the proposed revisions to the
pro forma LGIA and pro forma SGIA.\137\
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\137\ See, e.g., Order No. 2003, FERC Stats. & Regs. ] 31,146 at
P 827.
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60. The Commission would assess whether each compliance filing
satisfies the proposed requirements stated above and issue additional
orders as necessary to ensure that each public utility transmission
provider meets the requirements of the subsequent Final Rule.
61. The Commission also proposes that transmission providers that
are not public utilities would have to adopt the requirements of this
proposal and subsequent Final Rule as a condition of maintaining the
status of their safe harbor tariff or otherwise satisfying the
reciprocity requirement of Order No. 888.\138\
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\138\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,760-63.
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III. Information Collection Statement
62. The Paperwork Reduction Act (PRA) \139\ requires each federal
agency to seek and obtain Office of Management and Budget (OMB)
approval before undertaking a collection of information directed to ten
or more persons, or contained in a rule of general applicability. OMB's
regulations require the approval of certain information collection
requirements imposed by agency rules.\140\ Upon approval of a
collection of information, OMB will assign an OMB control number and an
expiration date. Respondents subject to the filing requirements of this
proposal will not be penalized for failing to respond to this
collection of information unless the collection of information displays
a valid OMB control number. Transmission providers are subject to the
proposed revisions to the pro forma LGIA and SGIA.
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\139\ 44 U.S.C. 3501-3520 (2012).
\140\ 5 CFR 1320.11 (2016).
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63. In this NOPR, the Commission proposes to amend its pro forma
LGIA and pro forma SGIA in accordance with section 35.28(f)(1) of its
regulations.\141\ The proposed revisions to the pro forma LGIA and pro
forma SGIA would require new large and small generating facilities to
install, maintain, and operate a functioning governor or equivalent
controls which the Commission proposes to define as the required
hardware and/or software that provides frequency responsive real power
control with the ability to sense changes in system frequency and
autonomously adjust the generating facility's real power output in
accordance with the proposed maximum droop and dead band parameters and
in the direction needed to correct frequency deviations. The NOPR
proposes to require each public utility transmission provider to amend
its pro forma LGIA and pro forma SGIA to require that all newly
interconnecting large and small generating facilities, as well as all
existing large and small generating facilities that take any action
that requires the submission of a new interconnection request that
results in the filing of an executed or unexecuted interconnection
agreement, to adhere to the proposed requirements, on or after the
effective date of any Final Rule issued in this proceeding.
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\141\ 18 CFR 35.28(f)(1) (2016).
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64. The reforms in this NOPR would require filings of pro forma
LGIAs and pro forma SGIAs with the Commission. The Commission
anticipates the proposed reforms, once implemented, would not
significantly change currently existing burdens on an ongoing basis.
With regard to those public utility transmission providers that believe
that they already comply with the proposed reforms in this NOPR, they
could demonstrate their compliance in the filing required 60 days after
publication of the Final Rule in the Federal Register. The Commission
will submit the proposed reporting requirements to OMB for its review
and approval under section 3507(d) of the Paperwork Reduction Act.\142\
The Commission will use FERC-516B as a temporary ``placeholder''
information collection number.\143\
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\142\ 44 U.S.C. 3507(d) (2012).
\143\ The reporting requirements in this NOPR would normally be
included under FERC-516 (OMB Control No. 1902-0096). However, FERC-
516 is pending review at OMB in an unrelated action. Because only
one item per OMB Control No. can be pending OMB review at a time,
the Commission is temporarily using the information collection
number FERC-516B (OMB Control No. 1902-0286) to ensure timely
submittal of this NOPR to OMB.
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Burden Estimate: \144\ The Commission believes that the burden
estimates below are representative of the average burden on
respondents. The estimated burden and cost for the requirements
contained in this NOPR follow.\145\
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\144\ Burden means the total time, effort, or financial
resources expended by persons to generate, maintain, retain,
disclose or provide information to or for a Federal agency,
including: The time, effort, and financial resources necessary to
comply with a collection of information that would be incurred by
persons in the normal course of their activities (e.g., in compiling
and maintaining business records) will be excluded from the
``burden'' if the agency demonstrates that the reporting,
recordkeeping, or disclosure activities needed to comply are usual
and customary.
\145\ For this information collection, the Commission staff
estimates that industry is similarly situated in terms of hourly
cost (wages plus benefits). Based on the Commission's average cost
(wages plus benefits) for 2016, the Commission is using $74.50/hour.
FERC 516B, in NOPR in RM16-6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Number of Annual number
respondents of responses Total number Average burden (hours) & cost Total annual burden hours & total
\146\ per respondent of responses ($) per response annual cost ($)
(1) (2) (1) * (2) = (4).......................... (3) * (4) = (5)
(3)
--------------------------------------------------------------------------------------------------------------------------------------------------------
LGIA & SGIA changes/revisions...... 74 1 74 10 hours; $745.00............ 740 hours; $55,130.00.
--------------------------------------------------------------------------------------------------------------------
Total.......................... .............. .............. 74 ............................. 740 hours; $55,130.00.
--------------------------------------------------------------------------------------------------------------------------------------------------------
There are no maintenance cost, installation cost or any additional
cost or requirements after year 1.
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\146\ The NERC Compliance Registry lists 80 entities that
administer a transmission tariff and provide transmission service.
The Commission identifies only 74 as being subject to the proposed
requirements because 6 are Canadian entities and are not under the
Commission's jurisdiction.
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Title: FERC-516B, Electric Rate Schedules and Tariff Filings.
Action: Revision of currently approved collection of information.
OMB Control No.: 1902-0286.
Respondents for this Rulemaking: Businesses or other for profit
and/or not-for-profit institutions.
Frequency of Information: One-time during year 1.
Necessity of Information: The Commission proposes to revise its
regulations to require all newly interconnecting large and small
[[Page 85188]]
generating facilities, both synchronous and non-synchronous, to
install, maintain, and operate equipment capable of providing primary
frequency response as a condition of interconnection. To implement
these requirements, the Commission proposes to revise the pro forma
LGIA and the pro forma SGIA.
Internal Review: The Commission has reviewed the proposed changes
and has determined that the changes are necessary. These requirements
conform to the Commission's need for efficient information collection,
communication, and management within the energy industry. The
Commission has assured itself, by means of internal review, that there
is specific, objective support for the burden estimates associated with
the information collection requirements.
65. Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426 [Attention:
Ellen Brown, Office of the Executive Director], email:
DataClearance@ferc.gov, Phone: (202) 502-8663, fax: (202) 273-0873.
66. Comments on the collection of information and the associated
burden estimate in the proposed rule should be sent to the Commission
in this docket and may also be sent to the Office of Information and
Regulatory Affairs, Office of Management and Budget, 725 17th Street
NW., Washington, DC 20503 [Attention: Desk Officer for the Federal
Energy Regulatory Commission], at the following email address:
oira_submission@omb.eop.gov. Please refer to OMB Control No. 1902-0286
in your submission.
IV. Environmental Analysis
67. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\147\ The
Commission concludes that neither an Environmental Assessment or an
Environmental Impact Statement is required for proposed revisions under
section 380.4(a)(15) of the Commission's regulations, which provides a
categorical exemption for approval of actions under sections 205 and
206 of the FPA relating to the filing of schedules containing all rates
and charges for the transmission or sale of electric energy subject to
the Commission's jurisdiction, plus the classification, practices,
contracts and regulations that affect rates, charges, classifications,
and services.\148\ The revisions proposed in this NOPR update and
clarify the application of the Commission's standard interconnection
requirements to synchronous and non-synchronous generators. Therefore,
this NOPR falls within the categorical exemptions provided in the
Commission's regulations, and therefore neither an Environmental
Assessment nor an Environmental Impact Statement is required.
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\147\ Order No. 486, Regulations Implementing the National
Environmental Policy Act, 52 FR 47897 (Dec. 17, 1987), FERC Stats. &
Regs. Preambles 1986-1990 ] 30,783 (1987).
\148\ 18 CFR 380.4(a)(15) (2015).
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V. Regulatory Flexibility Act
68. The Regulatory Flexibility Act of 1980 (RFA) \149\ generally
requires a description and analysis of proposed rules that will have
significant economic impact on a substantial number of small entities.
The RFA does not mandate any particular outcome in a rulemaking. It
only requires consideration of alternatives that are less burdensome to
small entities and an agency explanation of why alternatives were
rejected.
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\149\ 5 U.S.C. 601-612 (2012).
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69. The Small Business Administration (SBA) revised its size
standards (effective January 22, 2014) for electric utilities from a
standard based on megawatt hours to a standard based on the number of
employees, including affiliates. Under SBA's standards, some
transmission owners will fall under the following category and
associated size threshold: Electric bulk power transmission and
control, at 500 employees.\150\
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\150\ 13 CFR 121.201, Sector 22 (Utilities), NAICS code 221121
(Electric Bulk Power Transmission and Control).
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70. The Commission estimates that the total number of transmission
providers, both public and non-public, affected by this NOPR is
74.\151\ Of these, the Commission estimates that approximately 27.5
percent are small entities. The Commission estimates the average total
cost to each of these entities will be minimal, requiring on average 10
hours, or $745.00. According to SBA guidance, the determination of
significance of impact ``should be seen as relative to the size of the
business, the size of the competitor's business, and the impact the
regulation has on larger competitors.'' \152\ The Commission does not
consider the estimated burden to be a significant economic impact. As a
result, the Commission believes this NOPR would not have a significant
economic impact on a substantial number of small entities.
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\151\ The NERC Compliance Registry lists 80 entities that
administer a transmission tariff and provide transmission service.
The Commission identifies only 74 as being subject to the proposed
requirements because 6 are Canadian entities and are not under the
Commission's jurisdiction.
\152\ U.S. Small Business Administration, A Guide for Government
Agencies: How to Comply with the Regulatory Flexibility Act, at 18
(May 2012), https://www.sba.gov/sites/default/files/advocacy/rfaguide_0512_0.pdf.
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71. The Commission estimates that the total annual number of new
non-synchronous interconnections per year for the first few years of
potential implementation under this NOPR would be approximately 200,
representing approximately 5,000 MW of installed capacity. Of these,
the Commission estimates that the majority are small entities. The
Commission estimates the average total cost to each of these entities
will be minimal, requiring on average approximately $3,300 per MW of
installed capacity. According to SBA guidance, the determination of
significance of impact ``should be seen as relative to the size of the
business, the size of the competitor's business, and the impact the
regulation has on larger competitors.'' The Commission does not
consider the estimated burden to be a significant economic impact on
these entities because the cost is relatively minimal compared to the
average capital cost per MW for wind and solar PV generation.\153\
Additionally, the Commission does not believe that there will be
substantial additional costs for new synchronous generators because
synchronous generators already come equipped with governors that
provide the capability to provide primary frequency response.
Accordingly, the Commission believes that this NOPR would not have a
significant economic impact on a substantial number of small entities.
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\153\ LBNL estimates that capital cost per MW of installed wind
capacity is $1,690,000. See LBNL 2015 Wind Market Report (Aug.
2016), https://emp.lbl.gov/sites/all/files/2015-windtechreport.final_.pdf). NREL estimates that the capital cost per
MW of installed solar PV capacity is $1,770,000. See NREL U.S.
Photovoltaic Prices and Cost Breakdowns (Sep. 2015), https://www.nrel.gov/docs/fy15osti/64746.pdf.
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VI. Comment Procedures
72. The Commission invites interested persons to submit comments on
the matters and issues proposed in this notice to be adopted, including
any related matters or alternative proposals that commenters may wish
to discuss. Comments are due January 24, 2017. Comments must refer to
Docket No. RM16-6-000, and must include the commenter's name, the
organization they represent, if applicable, and their address in their
comments.
[[Page 85189]]
73. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's Web site at https://www.ferc.gov. The Commission accepts most standard word processing
formats. Documents created electronically using word processing
software should be filed in native applications or print-to-PDF format
and not in a scanned format. Commenters filing electronically do not
need to make a paper filing.
74. Commenters that are not able to file comments electronically
must send an original of their comments to: Federal Energy Regulatory
Commission, Secretary of the Commission, 888 First Street NE.,
Washington, DC 20426.
75. All comments will be placed in the Commission's public files
and may be viewed, printed, or downloaded remotely as described in the
Document Availability section below. Commenters on this proposal are
not required to serve copies of their comments on other commenters.
VII. Document Availability
76. 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) and
in the Commission's Public Reference Room during normal business hours
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A,
Washington, DC 20426.
77. From the Commission's Home Page on the Internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary, type
the docket number excluding the last three digits of this document in
the docket number field.
78. User assistance is available for eLibrary and the Commission's
Web site during normal business hours from the Commission's Online
Support at (202) 502-6652 (toll free at 1-866-208-3676) or email at
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202)502-8659. Email the Public Reference Room at
public.referenceroom@ferc.gov.
By direction of the Commission.
Issued: November 17, 2016.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
Appendix
List of Commenters (Docket No. RM16-6-000)
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------------------------------------------------------------------------
AES Companies................ AES Corporation/AES Energy Storage/Dayton
Power and Light Company/Indianapolis
Power and Light Company.
APPA, et al.................. American Public Power Association/Large
Public Power Council/Transmission Access
Policy Study Group.
AWEA......................... American Wind Energy Association.
Apex......................... Apex Compressed Air Energy Storage.
APS.......................... Arizona Public Service Company.
Bonneville................... Bonneville Power Administration.
CAISO........................ California Independent System Operator.
Chelan County................ Chelan County Public Utility District.
California Cities............ City of Anaheim/City of Azusa/City of
Banning/City of Colton/City of Pasadena/
City of Riverside.
EEI.......................... Edison Electric Institute.
EDP.......................... EDP Renewables North America.
EPRI......................... Electric Power Research Institute.
EPSA, et al.................. Electric Power Supply Association/
Independent Power Producers of New York/
New England Power Generators Association/
Western Power Trading Forum.
ELCON........................ Electricity Consumers Resource Council.
ESA.......................... Energy Storage Association.
Grid Storage Consulting...... Grid Storage Consulting.
Howard F. Illian............. Howard F. Illian
Idaho Power.................. Idaho Power Company.
Indicated ISOs/RTOs.......... Independent Electricity System Operator/
ISO New England/New York Independent
System Operator/PJM Interconnection/
Southwest Power Pool.
IEEE-P1547 Working Group..... Institute of Electrical and Electronics
Engineers (IEEE) P1547 Standards Working
Group.
IEEE-PES..................... IEEE Power and Energy Society Technical
Council.
ITC, et al................... International Transmission Company/
Michigan Electric Transmission Company/
ITC Great Plains/ITC Midwest.
Manitoba..................... Manitoba Hydro.
Microgrids Resources Microgrids Resources Coalition.
Coalition.
MISO......................... Midcontinent Independent System Operator.
MISO TOs..................... Midcontinent Independent System Operator
Transmission Owners.
NARUC........................ National Association of Regulatory
Utility Commissioners.
NRECA........................ National Rural Electric Cooperative
Association.
NERC......................... North American Electric Reliability
Corporation.
North American Generator North American Generator Forum.
Forum.
Nuclear Energy Institute..... Nuclear Energy Institute.
PG&E......................... Pacific Gas and Electric Company.
Peak Reliability............. Peak Reliability.
PJM Utilities Coalition...... PJM Utilities Coalition.
Powerex...................... Powerex Corp.
Public Interest Organizations Public Interest Organizations.
Ralph D. Masiello............ Ralph D. Masiello.
SDG&E........................ San Diego Gas & Electric Company.
Solar City................... Solar City Corporation.
SoCal Edison................. Southern California Edison Company.
Southern Company............. Southern Company.
Steel Producers.............. Steel Producers.
[[Page 85190]]
Tacoma Power................. Tacoma Power.
TVA.......................... Tennessee Valley Authority.
Tri-State Generation......... Tri-State Generation and Transmission
Association.
Union of Concerned Scientists Union of Concerned Scientists.
WIRAB........................ Western Interconnection Regional Advisory
Body.
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[FR Doc. 2016-28321 Filed 11-23-16; 8:45 am]
BILLING CODE 6717-01-P