Essential Reliability Services and the Evolving Bulk-Power System-Primary Frequency Response, 9182-9192 [2016-03837]
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Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
[Docket No. EL16–39–000]
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Tri-State Generation and Transmission
Association, Inc.; Notice of Petition for
Declaratory Order
Take notice that on February 17, 2016,
pursuant to Rule 207 of the
Commission’s Rules of Practice and
Procedure of the Federal Energy
Regulatory Commission’s (Commission),
18 CFR 385.207(2015), Tri-State
Generation and Transmission
Association, Inc. (Tri-State) filed a
petition for declaratory order finding
that Tri-State’s fixed cost recovery
proposal contained in revised Board
Policy 101 is consistent with the Public
Utility Regulatory Policies Act of 1978
and the Commission’s implementing
regulaltions, as more fully explained in
the petition.
Any person desiring to intervene or to
protest in this proceeding must file in
accordance with Rules 211 and 214 of
the Commission’s Rules of Practice and
Procedure (18 CFR 385.211 and
385.214) on or before 5:00 p.m. Eastern
time on the specified comment date.
Protests will be considered by the
Commission in determining the
appropriate action to be taken, but will
not serve to make protestants parties to
the proceeding. Any person wishing to
become a party must file a notice of
intervention or motion to intervene, as
appropriate. Such notices, motions, or
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to intervene or protest must serve a copy
of that document on the Petitioner.
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Persons unable to file electronically
should submit an original and 5 copies
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The filings in the above proceeding
are accessible in the Commission’s
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appropriate link in the above list. They
are also available for review in the
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Commission’s Public Reference Room in
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Comment Date: 5:00 p.m. Eastern time
on March 18, 2016.
Dated: February 18, 2016.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
SUPPLEMENTARY INFORMATION:
[FR Doc. 2016–03835 Filed 2–23–16; 8:45 am]
BILLING CODE 6717–01–P
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
[Docket No. RM16–6–000]
Essential Reliability Services and the
Evolving Bulk-Power System—Primary
Frequency Response
Federal Energy Regulatory
Commission, Energy.
ACTION: Notice of Inquiry.
AGENCY:
In this Notice of Inquiry, the
Federal Energy Regulatory Commission
(Commission) seeks comment on the
need for reforms to its rules and
regulations regarding the provision and
compensation of primary frequency
response.
DATES: Comments are due April 25,
2016.
ADDRESSES: You may submit comments,
identified by docket number and in
accordance with the requirements
posted on the Commission’s Web site,
https://www.ferc.gov. Comments may be
submitted by any of the following
methods:
• Agency Web site: Documents
created electronically using word
processing software should be filed in
native applications or print-to-PDF
format and not in a scanned format, at
https://www.ferc.gov/docs-filing/
efiling.asp.
• Mail/Hand Delivery: Those unable
to file electronically must 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:
SUMMARY:
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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.
1. In this Notice of Inquiry (NOI), the
Commission seeks comment on the need
for reforms to its rules and regulations
regarding the provision and
compensation of primary frequency
response. In recent years, the nation’s
electric supply portfolio has
transformed to a point where fewer
resources may now be providing
primary frequency response than when
the Commission considered this issue in
other relevant proceedings. As
discussed below, in light of the
changing resource mix and other factors,
it is reasonable to expect this trend to
continue. Considering the significance
of primary frequency response to the
reliable operation of the Bulk-Power
System,1 the Commission seeks input
on whether and what action is needed
to address the provision and
compensation of primary frequency
response.
2. Specifically, the Commission seeks
comment on whether amendments to
the pro forma Large Generator
Interconnection Agreement (LGIA) and
Small Generator Interconnection
Agreement (SGIA) are warranted to
require all new generation resources to
have frequency response capabilities as
a precondition of interconnection. The
Commission also seeks comment on the
performance of existing resources and
whether primary frequency response
requirements for these resources are
warranted. Further, the Commission
seeks comment on the requirement to
provide and compensate for primary
frequency response.
1 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).
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Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices
I. Background
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A. Technical Overview: The Nature and
Operation of Frequency Response
3. Reliably operating an
Interconnection 2 requires maintaining
balance between generation and load so
that frequency remains within
predetermined boundaries around a
scheduled value (60 Hz in the United
States). Interconnections occasionally
experience system contingencies (e.g.,
the loss of a large generator) that disrupt
the balance between generation and
load. These contingencies result in
frequency deviations that can
potentially cause under frequency load
shedding (UFLS), additional generation
tripping, or cascading outages.3
Consequently, some generators within
an Interconnection automatically deploy
frequency control actions, including
inertial response and primary frequency
response, during disturbances to arrest
and stabilize frequency deviations. The
reliability of the Bulk-Power System
depends in part on the operating
characteristics of generating resources
that balancing authorities 4 commit to
serve load. However, not all generating
resources provide frequency support
services, which are essential to
maintaining the reliability and stability
of the Bulk-Power System.5
4. Frequency response is a measure of
an Interconnection’s ability to arrest and
stabilize frequency deviations within
pre-determined limits following the
sudden loss of generation or load.
Frequency response is affected by the
collective responses of generation and
load resources throughout the entire
Interconnection. Inertial response,
primary frequency response, and
secondary frequency response all
contribute to stabilizing the Bulk-Power
System by correcting frequency
deviations.
2 An Interconnection is a geographic area in
which the operation of Bulk-Power System
components is synchronized. In the continental
United States, there are three Interconnections,
namely the Eastern, Electric Reliability Council of
Texas (ERCOT), 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. Automatic Underfrequency
Load Shedding and Load Shedding Plans Reliability
Standards, Notice of Proposed Rulemaking, 137
FERC ¶ 61,067 (2011).
4 The North American Electric Reliability
Corporation’s (NERC) 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.’’
5 As discussed below, NERC Reliability Standard
BAL–003–1 has requirements related to frequency
response, but it is applicable to balancing
authorities and not individual generating resources.
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5. Inertial response, or system inertia,
involves the release or absorption of
kinetic energy by the rotating masses of
online generation and load within an
Interconnection, and is the result of the
coupling between the rotating masses of
synchronous generation and load and
the electric system.6 An
Interconnection’s inertial response
influences how fast frequency drops
after the loss of generation and how fast
it rises after a reduction of load. The less
system inertia there is, the faster the rate
of change of frequency 7 during
disturbances. An adequate amount of
system inertia is important since
following the sudden loss of generation,
inertia serves to reduce the rate of
change of frequency, allowing time for
primary frequency response actions to
arrest the frequency deviation and
stabilize the power system.
6. Primary frequency response, net of
changes in generation real power (MW)
output and power consumed by load in
response to a frequency deviation, is the
first stage of overall frequency control,
begins within seconds after the
frequency changes, and is critical to the
reliable operation of the Bulk-Power
System.8 Primary frequency response is
mostly provided by the automatic and
autonomous actions (i.e., outside of
system operator control) of turbinegovernors, while some response is
provided by frequency responsive loads
due to changes in system frequency.
Primary frequency response actions are
intended to arrest the frequency
deviation until it reaches the minimum
frequency, or nadir.9 An important goal
for system planners and operators is for
the frequency nadir, during large
disturbances, to remain above the first
stage of firm UFLS set points within an
Interconnection. The time-frame to
arrest frequency deviations typically
ranges from five to 15 seconds,
depending on the Interconnection.
7. Secondary frequency response
involves changes to the MW output of
6 See, e.g., Use of Frequency Response Metrics to
Assess the Planning and Operating Requirements
for Reliable Integration of Variable Renewable
Generation, Ernest Orlando Lawrence Berkeley
National Laboratory, at 13–14 (December 2010),
available at: https://energy.lbl.gov/ea/certs/pdf/lbnl4142e.pdf (LBNL Frequency Response Metrics
Report).
7 Rate of change of frequency is mainly a function
of the magnitude of the loss of generation (or load)
and system inertia and is measured in Hz/second.
8 See, e.g., LBNL Frequency Response Metrics
Report at 15–16.
9 The point at which the frequency decline is
arrested (following the sudden loss of generation)
is called the frequency nadir, and represents the
point in which the net primary frequency response
(MW) output from all generating units and the
decrease in power consumed by the load within an
Interconnection matches the net initial MW loss of
generation.
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resources on automatic generation
control (e.g., regulation resources) that
respond to dispatch instructions.10
Secondary frequency response actions
usually begin after 30 seconds or more
following a contingency, and can take 5
minutes or more to restore system
frequency to its scheduled value.
B. Evolving Generation Resource Mix
8. The nation’s generation resource
mix is undergoing a transformation that
includes the retirement of baseload,
synchronous units, with large rotational
inertia. The changing resource mix also
includes the integration of more
distributed generation, demand
response, and natural gas resources, and
the rapid expansion of variable energy
resources (VERs) 11 such as wind and
solar.12 Several factors, such as existing
and proposed federal and state
environmental regulations, renewable
portfolio standards, tax incentives, and
low natural gas prices, have driven
these developments.
9. During 2015, natural gas-fired
generation surpassed coal as the
predominant fuel source for electric
generation, and is now the leading fuel
type for capacity additions.13 In
addition, NERC recently determined
that there has been almost 50 GW of
baseload (e.g., coal, nuclear, petroleum,
and natural gas) retirements since
2011.14
10. In addition, between 2014 and
2015, all three U.S. Interconnections
have experienced growth in the
installed nameplate capacity of wind
and solar generation. For example, as
illustrated by the figure below, NERC
10 See e.g., LBNL Frequency Response Metrics
Report at 9–11.
11 For the purposes of this proceeding, the term
Variable Energy Resource refers to 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. This includes, for example,
wind, solar thermal and photovoltaic, and
hydrokinetic generating facilities. See Integration of
Variable Energy Resources, Order No. 764, FERC
Stats. & Regs. ¶ 31,331 at n. 1 (2012), order on reh’g
and clarification, Order No. 764–A, 141 FERC ¶
61,232 (2012), order on clarification and reh’g,
Order No. 764–B, 144 FERC ¶ 61,222 (2013).
12 The Solar Energy Industries Association (SEIA)
recently reported that more than 50 percent of
newly installed electric generating capacity in the
U.S. came from solar generation in the first quarter
of 2015. See SEIA Solar Market Insight Report 2015
Q1 (2015), https://www.seia.org/research-resources/
solar-market-insight-report-2015-q1.
13 See NERC 2015 Long Term Reliability
Assessment at 1 (December 2015), https://
www.nerc.com/pa/RAPA/ra/
Reliability%20Assessments%20DL/2015LTRA%20%20Final%20Report.pdf.
14 See NERC 2015 Summer Reliability
Assessment at 5 (May 2015), https://www.nerc.com/
pa/RAPA/ra/Reliability%20Assessments%20DL/
2015_Summer_Reliability_Assessment.pdf.
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solar capacity, representing a growth
rate of 12 percent and 116 percent over
the respective 2014 levels of 33.5 GW
and 0.73 GW;16 (2) ERCOT had 14.7 GW
of wind and 0.18 GW of solar,
representing a growth rate of 29 percent
and 50 percent over the respective 2014
levels of 11.4 GW and 0.12 GW;17 and
(3) Western Interconnection had 24.8
GW of wind and 8.4 GW of solar,
representing a growth rate of 17 percent
and 11 percent over the respective 2014
levels of 21.1 GW and 7.6 GW.18
11. The changing generation resource
mix has the potential to reduce the
inertial response within some
Interconnections, as VERs do not
contribute to inertia unless they are
specifically designed to do so. For
example, solar photovoltaic resources
have no rotating mass and thus no
rotational inertia. Similarly, while wind
turbines have a rotating mass, power
converters that interconnect modern
wind turbines decouple the rotation of
their turbines from the grid. As such,
modern wind turbines do not contribute
to the system’s inertia unless
specifically configured to do so.19
Therefore, increased numbers of VERs,
in conjunction with significant
retirements of large conventional
resources with large rotational inertia,
have the potential to reduce system
inertia.
12. In addition, VERs do not provide
primary frequency response unless
specifically configured to do so.
Furthermore, since VERs typically have
low marginal costs of production, they
would likely not be dispatched in a
manner necessary to provide primary
frequency response, since the provision
of primary frequency response involves
the reservation of capacity (or
‘‘headroom’’) in order for a resource to
automatically increase its MW output in
response to drops in system frequency.
Therefore, there is a significant risk that,
as conventional synchronous resources
retire or are displaced by increased
numbers of VERs that do not typically
have primary frequency response
capabilities, the net amount of
frequency responsive generation online
will be reduced.20
13. The combined impacts of lower
system inertia and lower frequency
responsive capability online may
adversely affect reliability during
disturbances because lower system
inertia results in more rapid frequency
deviations during disturbances. This, in
turn, may result in lower frequency
nadirs, particularly if the primary
frequency capability online is not
sufficiently fast. This is a potential
reliability concern because, as the
frequency nadir lowers, it approaches
the Interconnection’s UFLS trip setting,
which could result in the loss of load
and additional generation across the
Interconnection.
14. These developments and their
potential impacts could challenge
system operators in maintaining
reliability. The Commission believes
that a substantial body of evidence has
emerged warranting consideration of
possible actions to ensure that resources
capable of providing primary frequency
15 NERC 2015 Summer Reliability Assessment,
Table 3 at page 7.
16 Id.
17 Id.
18 Id.
19 See, e.g., General Electric WindINERTIA
Control Fact Sheet (2009), https://site.ge-energy.com/
prod_serv/products/renewable_energy/en/
downloads/GEA17210.pdf.
20 Non-synchronous generators such as VERs
(e.g., wind and solar resources) produce electricity
that is not synchronized to the electric grid (i.e.,
direct current (DC) power or alternating current
(AC) power at a frequency other than 60 hertz).
Inverters convert non-synchronized AC or DC
power into synchronized AC power that can be
transmitted on the transmission system. These
resources do not operate in the same way as
conventional generators and respond differently to
network disturbances.
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has observed that the three
Interconnections collectively added
approximately 11.1 GW of wind and
1.73 GW of solar generation between
2014 and 2015.15 More specifically, in
2015: (1) The Eastern Interconnection
had 37.6 GW of wind and 1.6 GW of
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response are adequately maintained as
the nation’s resource mix continues to
evolve.
15. 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.21 The Task Force focused on
three essential reliability services:
frequency support, ramping capability,
and voltage support.22
16. The Task Force considered the
seven ancillary services 23 adopted by
the Commission in Order Nos. 888 24
and 890 25 as a subset of the essential
reliability services that may need to be
augmented by additional services as the
Bulk-Power System characteristics
change. However, the Task Force did
not intend to recommend new reliability
standards or propose actions to alter the
existing suite of ancillary services.26
Instead, its focus was on educating and
informing industry and other
stakeholders about essential reliability
services, developing measures and
industry best practices for tracking
essential reliability services, and
developing recommendations to ensure
21 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 (April 2014), https://www.nerc.com/
comm/Other/essntlrlbltysrvcstskfrcDL/Scope_
ERSTF_Final.pdf.
22 Essential Reliability Services Task Force
Measures Report at 22 (December 2015), https://
www.nerc.com/comm/Other/
essntlrlbltysrvcstskfrcDL/
ERSTF%20Framework%20Report%20%20Final.pdf.
23 The seven ancillary services 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.
24 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).
25 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).
26 NERC Essential Reliability Services Task Force
Scope Document at 2.
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that essential reliability services
continue to be provided as the nation’s
generation resource mix evolves.27
17. The reliability of the Bulk-Power
System will be increasingly dependent
upon the operational characteristics of
natural gas and renewable generating
units, as these types of resources are
expected to comprise an increasing
percentage of the future generation
resource mix. The Task Force stated that
‘‘the reliability of the electric grid
depends on the operating characteristics
of the replacement resources.’’ 28 NERC
observed that ‘‘wind, solar, and other
variable energy resources that are an
increasingly greater share of the BulkPower System provide a significantly
lower level of essential reliability
services than conventional
generation.’’ 29 The Task Force
concluded that it is prudent and
necessary to ensure that primary
frequency capabilities are present in the
future generation resource mix, and
recommends that all new generators
support the capability to manage
frequency.30
18. Contributing to the concerns
associated with the nature and
operational characteristics of the
evolving resource mix is the uncertainty
whether a resource configured to
provide primary frequency response is
willing and able to offer such a service
when called upon to do so. While
almost all existing synchronous
resources and some non-synchronous
resources have governors or equivalent
control equipment capable of providing
primary frequency response, generator
owners and operators can
independently decide whether units
provide primary frequency response.31
19. For example, at present, it is
possible for a generator owner/operator
to block or disable the governor or to set
a wide dead band setting. A wide dead
band setting can result in a unit not
providing primary frequency response
for most frequency deviations. As
discussed more fully below, in February
2015, NERC issued an Industry
27 Id.
28 Essential Reliability Services Task Force
Measures Report at iv.
29 See NERC State of Reliability 2015 Report at 16
(May 2015), https://www.nerc.com/pa/RAPA/PA/
Performance%20Analysis%20DL/
2015%20State%20of%20Reliability.pdf.
30 Essential Reliability Services Task Force
Measures Report at vi.
31 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 MW output due to variations in
system frequency. A governor also has a dead band
which establishes a minimum frequency deviation
(from nominal) that must be exceeded in order for
the governor to act. Example droop and dead band
settings are 5 percent and ±0.036 Hz, respectively.
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Advisory which determined that a
significant portion of generators within
the Eastern Interconnection utilize dead
bands or governor control settings that
either inhibit or prevent the provision of
primary frequency response.32 In
response to this issue and other
concerns, NERC’s Operating Committee
recently approved a 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.33
20. NERC’s State of Reliability Report
for 2015 explained that the three U.S.
Interconnections currently exhibit stable
frequency response performance above
their Interconnection Frequency
Response Obligations.34 However,
NERC has pointed out a historic decline
in frequency response performance in
both the Western and Eastern
Interconnections.35 NERC identified
several key reasons for the decline,
mainly tied to the primary frequency
response performance of generators.36
C. Prior Commission and Industry
Actions
21. In this proceeding, the
Commission seeks comment on the need
32 NERC Generator Governor Frequency Response
Industry Advisory (February 2015), https://
www.nerc.com/pa/rrm/bpsa/Alerts%20DL/
2015%20Alerts/NERC%20Alert%20A-2015-02-0501%20Generator%20Governor%20Frequency%20
Response.pdf.
33 See NERC Primary Frequency Control
Guideline Final Draft (December 2015), https://
www.nerc.com/comm/OC/
Reliability%20Guideline%20DL/Primary_
Frequency_Control_final.pdf. See also NERC
Operating Committee Meeting Minutes (January
2016), https://www.nerc.com/comm/OC/Agendas
HighlightsMinutes/Operating%20
Committee%20Minutes%20-%20Dec%2015-16
%202015-Final.pdf.
34 NERC State of Reliability Report 2015 at 9 (May
2015). See https://www.nerc.com/pa/RAPA/PA/
Performance%20Analysis%20DL/2015%20State
%20of%20Reliability.pdf. Reliability Standard
BAL–003–1 establishes Interconnection Frequency
Response Obligations that are designed to require
sufficient frequency response for each
Interconnection to arrest frequency declines even
for severe, but possible, contingencies.
35 See NERC Frequency Response Initiative
Industry Advisory—Generator Governor Frequency
Response at slide 10 (April 2015), https://
www.nerc.com/pa/rrm/Webinars%20DL/Generator_
Governor_Frequency_Response_Webinar_April_
2015.pdf. See also Review of the Recent Frequency
Performance of the Eastern, Western and ERCOT
Interconnections, Ernest Orlando Lawrence
Berkeley National Laboratory, at pp xiv–xv
(December 2010), https://energy.lbl.gov/ea/certs/pdf/
lbnl-4144e.pdf.
36 See NERC Frequency Response Initiative
Report: The Reliability Role of Frequency Response
(October 2012), https://www.nerc.com/docs/pc/FRI_
Report_10-30-12_Master_w-appendices.pdf
(Frequency Response Initiative Report).
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for reforms to its rules and regulations
regarding the provision of primary
frequency response. This section offers
an overview of Commission and
industry action to date related to
frequency response to provide the
context for the consideration of what, if
any, actions the Commission should
take to ensure that adequate frequency
response is available to maintain grid
reliability.
22. In April 1996, the Commission
issued Order No. 888, to address undue
discrimination in transmission service
by requiring all public utilities to
provide open access transmission
service consistent with the terms of a
pro forma Open Access Transmission
Tariff (OATT).37 The pro forma OATT
sets forth the terms of transmission
service including, among other things,
the provision of ancillary services.
Additionally, the Commission adopted
six ancillary services stating they are
‘‘needed to accomplish transmission
service while maintaining reliability
within and among control areas affected
by the transmission service.’’ 38 The
ancillary service involved in this
proceeding is Regulation and Frequency
Response Service, found in Schedule 3
of the pro forma OATT.
23. In July 2003, the Commission
issued Order No. 2003, which revised
the pro forma OATT to include a pro
forma LGIA, which applies to
interconnection requests of large
generators (i.e., generators larger than 20
MW).39 While the pro forma LGIA
adopted standard procedures and a
standard agreement for the
interconnection of large generating
facilities, it was ‘‘designed around the
needs of large synchronous
generators.’’ 40 The Commission also
added a blank Appendix G
(Requirements of Generators Relying on
Newer Technologies) to the LGIA to
serve as a means by which to apply
interconnection requirements specific
for generators relying on newer
technologies, such as wind generators.41
24. In May 2005, the Commission
issued Order No. 2006, which required
all public utilities to adopt standard
37 Order
No. 888, FERC Stats. & Regs. ¶ 31,036.
at 31,705.
39 Standardization of Generator Interconnection
Agreements and Procedures, Order No. 2003, FERC
Stats. & Regs. ¶ 31,146, app. 6 (LGIP), app. C (LGIA)
(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).
40 Order No. 2003–A, FERC Stats. & Regs.
¶ 31,160 at P 407 & n.85.
41 Id.
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terms and conditions for new
interconnecting small generators (i.e.,
those no larger than 20 MW) under a pro
forma SGIA.42
25. The Commission recently issued a
notice of proposed rulemaking to revise
the pro forma LGIA and SGIA to
eliminate the exemption for wind
generators and other non-synchronous
generators regarding reactive power
requirements.43 The proposed rule
proposes to require all newly
interconnecting generators, both
synchronous and non-synchronous, to
provide reactive power.
26. Although the Commission has
previously included technical
requirements for generators in the LGIA
and Large Generator Interconnection
Procedures (LGIP),44 both the pro forma
LGIA and SGIA are silent with respect
to primary frequency response
requirements.
27. In a final rule issued on January
16, 2014, the Commission approved
Reliability Standard BAL–003–1, which
establishes frequency response
requirements for balancing
authorities.45 Reliability Standard BAL–
003–1 established Interconnection
Frequency Response Obligations that
prescribe the minimum frequency
response that must be maintained by an
Interconnection. The purpose of the
Interconnection Frequency Response
Obligation is to maintain the minimum
frequency (nadir) above UFLS set points
following the largest contingency of the
Interconnection as defined by the
resource contingency criteria in BAL–
003–1. Each balancing authority is
assigned a Frequency Response
Obligation 46 that is a proportionate
42 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).
43 Reactive Power Requirements for NonSynchronous Generation, 153 FERC ¶ 61,175 (2015).
44 For example, in Order Nos. 661 and 661–A, the
Commission adopted standard procedures and
technical requirements related to low voltage ride
thru and power factor design criteria for the
interconnection of large wind plants, and required
all public utilities that own, control, or operate
facilities for transmitting electric energy in
interstate commerce to append Appendix G to their
LGIPs and LGIAs in their OATTs to include these
requirements. Interconnection for Wind Energy,
Order No. 661, FERC Stats. & Regs. ¶ 31,186, order
on reh’g, Order No. 661–A, FERC Stats. & Regs.
¶ 31,198 (2005).
45 Frequency Response and Frequency Bias
Setting Reliability Standard, Order No. 794, 146
FERC ¶ 61,024 (2014). Reliability Standards
proposed by NERC are submitted to the
Commission for approval pursuant to section 215(d)
of the FPA; 16 U.S.C. 824o(d).
46 NERC’s Glossary of Terms defines Frequency
Response Obligation as ‘‘[t]he balancing authority’s
share of the required Frequency Response needed
for the reliable operation of an Interconnection.’’
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share of the Interconnection Frequency
Response Obligation, and is based on its
annual generation and load.47
Requirement R1 of BAL–003–1 requires
each balancing authority to achieve an
annual Frequency Response Measure
that equals or exceeds its Frequency
Response Obligation. The Frequency
Response Measure is the median value
of a balancing authority’s frequency
response performance during selected
events over the course of a year.48
Requirement R1 of BAL–003–1 becomes
effective on April 1, 2016, and
compliance begins on December 1,
2016.
28. Although Reliability Standard
BAL–003–1 requires sufficient
frequency response from balancing
authorities, on average, to maintain
Interconnection frequency, it does not
require generators to provide primary
frequency response. In the rulemaking
in which the Commission approved
Reliability Standard BAL–003–1, some
commenters expressed concern that the
standard does not address the
availability of generator resources to
provide primary frequency response or
the premature withdrawal 49 of primary
frequency response. In Order No. 794,
the Commission directed NERC to
submit a report by July 2018 analyzing
the availability of resources for each
balancing authority and Frequency
Response Sharing Group 50 to meet their
Frequency Response Obligation.51
Furthermore, the Commission stated
that, if NERC learns that balancing
authorities are experiencing difficulty in
procuring sufficient resources to satisfy
their Frequency Response Obligations,
47 The Interconnection Frequency Response
Obligation and Frequency Response Obligation are
expressed in MW per 0.1 Hertz (MW/0.1 Hz).
48 Attachment A of BAL–003–1. NERC will
identify between 20 to 35 events annually in each
Interconnection for calculating the Frequency
Response Measure. See also Procedure for ERO
Support of Frequency Response and Frequency Bias
Setting Standard, (November 30, 2012), https://
www.nerc.com/pa/Stand/Project%20200712%20
Frequency%20Response%20DL/Procedure_Clean_
20121130.pdf.
49 NERC has stated that ‘‘[w]ithdrawal of primary
frequency response is an undesirable characteristic
associated most often with digital turbine-generator
control systems using setpoint output targets for
generator output. These are typically outer-loop
control systems that defeat the primary frequency
response of the governors after a short time to
return the unit to operating at a requested MW
output.’’ See Order No. 794, 146 FERC ¶ 61,024 at
P 65 (citing NERC’s Frequency Response Initiative
Report).
50 NERC’s Glossary of Terms defines a Frequency
Response Sharing Group as a ‘‘group whose
members consist of two or more Balancing
Authorities that collectively maintain, allocate, and
supply operating resources required to jointly meet
the sum of the Frequency Response Obligations of
its members.’’
51 Order No. 794, 146 FERC ¶ 61,024 at P 60.
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NERC should immediately report it to
the Commission with appropriate
recommendations for mitigation.52
29. Additionally, in Order No. 794,
the Commission stated that the nature
and extent of the problems that could
result from the premature withdrawal of
primary frequency response, and how
best to address them, will be better
understood after NERC and balancing
authorities have more experience with
Reliability Standard BAL–003–1.53 The
Commission also stated that the need to
take action regarding the premature
withdrawal of primary frequency
response, including requiring load
controllers to include a frequency bias
term to sustain frequency response or
otherwise modifying Reliability
Standard BAL–003–1, should be
decided after we have actual experience
with the Reliability Standard.54
30. In light of the ongoing evolution
of the nation’s generation resource mix,
and other factors, such as NERC’s
Generator Governor Industry Advisory
released in February 2015, the
Commission believes that it is prudent
to take a proactive approach to better
understand the issues related to primary
frequency response performance and
determine what additional actions
beyond Reliability Standard BAL–003–1
may be appropriate. Thus, the
Commission is proceeding with a Notice
of Inquiry at this time rather than
waiting until NERC submits a report in
2018.
31. In the absence of national primary
frequency response requirements
applicable to individual generating
resources, some areas, including
ERCOT, ISO New England Inc. (ISO–
NE), and PJM Interconnection, L.L.C.
(PJM), have implemented regional
requirements for individual generating
resources within their regions in order
to maintain reliability.
32. For example, the Commission
accepted Texas Reliability Entity Inc.’s
Regional Reliability Standard BAL–001–
TRE–01 (Primary Frequency Response
in the ERCOT Region) as mandatory and
enforceable, which places requirements
on generator owners and operators with
respect to the provision of primary
frequency response within the ERCOT
region.55 In particular, BAL–001–TRE–
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52 Id.
P 63.
P 75.
54 Id. P 76.
55 North American Electric Reliability
Corporation, 146 FERC ¶ 61,025 (2014). The
requirements of BAL–001–TRE–01 help to ensure
that generation and load remain balanced—or are
quickly restored to balance—in the ERCOT
Interconnection so that system frequency is restored
to stability and near normal frequency even after a
significant event occurs on the system. In Order No.
53 Id.
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01 requires generator owners to operate
each generating unit/generating facility
that is connected to the interconnected
transmission system with the governor
in service and responsive to frequency
when the generating unit/generating
facility is online and released for
dispatch, and to promptly notify the
balancing authority of any change in
governor status.56 Additionally, BAL–
001–TRE–01 requires generator owners
to set specified governor dead band and
droop parameters.57 Moreover, BAL–
001–TRE–01 requires generator owners
to provide minimum initial and
sustained primary frequency response
performance.58 NERC recently noted
that ERCOT experienced a significant
improvement in its frequency response
performance as generators within its
region adjusted their governor settings
for compliance with BAL–001–TRE–
01.59
33. ISO–NE requires each generator
within its region with a capability of ten
MW or more, including renewable
resources, to operate with a functioning
governor with specified dead band and
droop settings, and to also ensure that
the provision of primary frequency
response is not inhibited by the effects
of outer-loop controls.60
34. PJM has pro forma
interconnection agreements that obligate
interconnection customers within its
region to abide by all PJM rules and
procedures pertaining to generation and
transmission, including rules and
procedures set forth in the PJM
Manuals.61 PJM requires large,
conventional generators to operate on
unrestricted governor control to assist in
maintaining Interconnection frequency,
and recently established specified
governor dead band and droop
693, the Commission approved a regional difference
for the ERCOT Interconnection from Reliability
Standard BAL–001–0, allowing ERCOT to be
exempt from Requirement R2, and found that
ERCOT’s approach to frequency response under its
own market protocols appeared to be more stringent
than Requirement R2. Order No. 693, FERC Stats.
& Regs. ¶ 31,242 at PP 313–315.
56 Reliability Standard BAL–001–TRE–01, at
Requirements R7 and R8.
57 Reliability Standard BAL–001–TRE–01, at
Requirement R6.
58 Reliability Standard BAL–001–TRE–01, at
Requirements R9 and R10.
59 NERC 2014 Frequency Response Annual
Analysis Report at 6 (February 2015), https://
www.nerc.com/FilingsOrders/us/
NERC%20Filings%20to%20FERC%20DL/Final_
Info_Filing_Freq_Resp_Annual_Report_
03202015.pdf. See also Table 3 at 6.
60 Section I of ISO–NE’s Operating Procedure No.
14—Technical Requirements for Generators,
Demand Resources, Asset Related Demands and
Alternative Technology Regulation Resources,
https://www.iso-ne.com/rules_proceds/operating/
isone/op14/op14_rto_final.pdf.
61 PJM Tariff, Attachment O § 8.0.
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requirements for all generating
resources (excluding nuclear units) with
a gross plant/facility aggregate
nameplate rating greater than 75 MVA.62
In addition, PJM recently added new
interconnection requirements for
interconnection customers entering its
queue after May 2015 and seeking to
interconnect non-synchronous
generators, including wind generators,
to use ‘‘enhanced inverters’’ with the
capability to, among other things,
provide primary frequency response.63
PJM stated that the installed capacity of
VERs in its region is expected to
increase to approximately 15 GW by the
2016–17 delivery year, and that it has an
additional 25 GW of VERs in its
interconnection queue.64 PJM expressed
a need for VERs to install the capability
to automatically reduce or increase their
real power output in order to respond to
a variety of system conditions,
including high or low frequencies. PJM
also stated that this capability will
provide flexibility in responding to
transmission system events using all
available resources which, according to
PJM, will be increasingly important as
VERs displace synchronous generators
that have these capabilities.65
D. Compensation for Primary Frequency
Response Service
35. This section offers an overview of
Commission and industry action to date
related to compensation for primary
frequency response. At present, there
are few, if any, entities receiving
compensation for selling primary
frequency response as a stand-alone
product, and there are no current rates
applicable to sales of primary frequency
response alone. However, several
options for transactions involving
primary frequency response have been
developed. Transmission providers may
sell primary frequency response service
in combination with regulation service
under the bundled pro forma OATT
Schedule 3 product, Regulation and
Frequency Response Service.66
62 PJM
Manual 14D.
Interconnection, L.L.C., 151 FERC ¶
61,097, at n.58 (2015).
64 PJM Interconnection, L.L.C., Transmittal Letter,
Docket No. ER15–1193–000, at 2 (filed Mar. 6,
2015).
65 Id. at 11.
66 Regulation service is different than primary
frequency response because regulation resources
respond to automatic generation control signals,
which responds to Area Control Error. Regulation
is centrally coordinated by the balancing authority.
Primary frequency response, in contrast, is
autonomous and is not centrally coordinated.
Schedule 3 lumps these different services together,
despite their differences. The Commission in Order
No. 888 found that ‘‘while the services provided by
Regulation Service and Frequency Response Service
63 PJM
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Schedule 3 in the pro forma OATT in
Order Nos. 888 67 and 890 68 permits
jurisdictional transmission providers to
outline their rates for this regulation and
frequency response service through a
filing under FPA section 205. Schedule
3 charges are cost-based rates paid by
transmission customers to the
transmission provider. Additionally,
Order No. 784 made it possible for
third-party sellers to offer Schedule 3
service to the transmission provider at
a rate up to the published Schedule 3
rate, or at rates that result from an
appropriate competitive solicitation.69
Such third-party sales could involve any
combination of regulation and primary
frequency response services, including
unbundled primary frequency response
service by itself.
36. Finally, in Order No. 819, the
Commission revised its regulations to
foster competition in the sale of primary
frequency response service.70 In the
final rule, the Commission approved the
sale of primary frequency response
service at market-based rates by entities
that qualify for market-based rate
authority for sales of energy and
capacity to any willing buyer. Order No.
819 focused on how jurisdictional
entities can qualify for market-based
rates for primary frequency response
service in the context of voluntary
bilateral sales, and did not place any
limits on the types of transactions
available to procure primary frequency
response service; they may be costbased or market-based, bundled with
other services or unbundled, and inside
or outside of organized markets.71 Order
No. 819 did not require any entity to
purchase primary frequency response
from third parties or develop an
organized market for primary frequency
response.72
are different, they are complementary services that
are made available using the same equipment. For
this reason, we believe that Frequency Response
Service and Regulation Service should not be
offered separately, but should be offered as part of
one service.’’ Order No. 888, FERC Stats. & Regs.
¶ 31,036, at PP 212–213 (1996).
67 Order No. 888, FERC Stats. & Regs. ¶ 31,036.
68 Order No. 890, FERC Stats. & Regs. ¶ 31,241.
69 Third-Party Provision of Ancillary Services;
Accounting and Financial Reporting for New
Electric Storage Technologies, Order No. 784, FERC
Stats. & Regs. ¶ 31,349, at PP 6–7 (2013), order on
clarification, Order No. 784–A, 146 FERC ¶ 61,114
(2014).
70 Third-Party Provision of Primary Frequency
Response Service, Order No. 819, 153 FERC
¶ 61,220 (2015).
71 Id. P 13.
72 Id. P 37. The Commission denied Calpine
Corporation’s request for Regional Transmission
Organizations (RTOs) and Independent System
Operators (ISOs) to be given a deadline to develop
tariff changes that would enable them to implement
primary frequency response compensation
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II. Request for Comments
37. The Commission seeks comment
on the need for reforms to its rules and
regulations regarding the provision and
compensation of primary frequency
response. Specifically, the Commission
seeks comment on possible actions to
ensure that the provision of primary
frequency response continues to remain
at levels adequate to maintain the
reliability of the Bulk-Power System in
light of the ongoing transformation of
the nation’s generation resource mix.
The Commission understands that this
transformation in the nation’s
generation portfolio could eventually
result in a reduction of system inertia
and fewer generation resources with
primary frequency response capabilities.
In addition, as discussed above, NERC
has indicated that a significant number
of generators within the Eastern
Interconnection utilize dead bands or
governor control settings that either
inhibit or prevent the provision of
primary frequency response. Together,
these factors could result in potential
downward shifts of the frequency nadir
during disturbances, closer to UFLS set
points that would trigger significant
widespread outages.
38. Presently, there are no pro forma
agreements for primary frequency
response transactions. Voluntary sales
of primary frequency response, would
most likely involve negotiated, bilateral
contracts between buyers and sellers. In
this regard, considering their
compliance obligations under
Reliability Standard BAL–003–1,
balancing authorities will be the most
likely source of demand for voluntary
purchases of primary frequency
response service from third-party
sellers, including those who have not
provided the service in the past.
Accordingly, as discussed further
below, the Commission seeks comment
on whether and to what extent
balancing authority demand for
voluntary purchases of frequency
response would be reduced if all or all
newly interconnecting resources were
required to provide frequency response
service. Further, we also seek comment
on the impact this would have on the
Commission’s efforts under Order No.
819 to foster the development of a
bilateral market for market-based rate
sales of primary frequency response
service as a means of cost-effectively
meeting such demand.
39. Within RTO/ISO markets, no
current stand-alone primary frequency
response product exists. Any RTO/ISO
that desires to explicitly procure and
compensate primary frequency response
would need new tariff provisions
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because no RTO/ISO currently defines
or procures such a product. As
discussed below, the Commission seeks
comment on the need for and the nature
of frequency response compensation
within the context of current RTO/ISO
market optimization processes.
40. Accordingly, the Commission
seeks comment on the following
possible actions, discussed in more
detail below: (1) Modifications to the
pro forma LGIA and SGIA mandating
primary frequency response
requirements for new resources, among
other changes; (2) new primary
frequency response requirements for
existing resources; and (3) the
requirement to provide and compensate
for primary frequency response.
A. Modifications to the pro forma LGIA
and SGIA
41. Reliability Standard BAL–003–1
and the pro forma LGIA and SGIA do
not specifically address generators’
provision of primary frequency
response. Article 9.6.2.1 of the pro
forma LGIA (Governors and Regulators)
requires that if speed governors are
installed, they should be operated in
automatic mode.73 Reliability Standard
BAL–003–1 and the pro forma LGIA and
SGIA do not explicitly: (1) Require
generators to install the necessary
capability to provide primary frequency
response; (2) prescribe specific governor
settings that would support the
provision of primary frequency
response; 74 or (3) establish generator
primary frequency response
performance requirements during
disturbances (e.g., require the response
to be sustained, and not prematurely
withdrawn prior to the initiation of
secondary frequency response actions to
return system frequency back to its
nominal value and back within a
generator’s dead band setting).75
42. The Commission’s pro forma
generator interconnection agreements
and procedures were developed at a
time when traditional generating
resources with standard governor
controls and large rotational inertia
were the predominant sources of
electricity generation. However,
circumstances are evolving, with NERC
and others predicting significant
73 Order No. 2003, FERC Stats. & Regs. ¶ 31,146,
app. C (LGIA).
74 Generator governors can be enabled or disabled
which determines whether or not primary
frequency response is provided at all by the
generator. In addition, even if a governor is enabled,
its control settings can limit the conditions under
which the generator provides primary frequency
response.
75 Primary frequency response would not be
expected to be provided if no capacity (or
‘‘headroom’’) is reserved on a unit.
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retirements of conventional
synchronous resources, all of which
contribute to system inertia, and some
of which provide primary frequency
response. In addition, VERs are
projected to comprise an increasing
portion of the installed capacity in
many regions of the country, but they do
not typically provide inertial response
or primary frequency response unless
specifically configured to do so.
43. Regarding VERs, the Commission
understands that in previous years,
many non-synchronous resources were
not consistently designed with primary
frequency response capabilities.
However, NERC and others have stated
that VER manufacturers have made
significant advancements in recent years
to develop the necessary controls that
would enable VERs to provide
frequency response.76 NERC
recommends that the industry analyze
how wind and solar photovoltaic
resources can contribute to frequency
response and to work toward
interconnection requirements that
ensure system operators will continue to
maintain essential reliability services.77
Also relevant are PJM’s recent additions
of new interconnection requirements for
VERs entering its queue after May
2015.78 PJM has stated that the
necessary capabilities for nonsynchronous resources to provide
primary frequency response, among
other services, are now ‘‘baked in’’ as
enhancements to inverter capabilities.79
44. In light of the ongoing changes in
the nation’s resource mix as well as
NERC’s concerns regarding the primary
frequency response performance of
existing resources, the Commission
seeks comment on whether and how to
modify the pro forma LGIA and SGIA to
require primary frequency response
capability and performance of new
generating resources.
45. To that end, the Commission seeks
comment on the following questions:
1. Should the pro forma LGIA and
SGIA be revised to include requirements
for all newly interconnecting generating
resources, including non-synchronous
resources, to:
1.1. Install the capability necessary to
provide primary frequency response?
1.2. Ensure that prime mover
governors (or equivalent frequency
control devices) are enabled and set
76 NERC Long Term Reliability Assessment at 27
(November 2014), https://www.nerc.com/pa/RAPA/
ra/Reliability%20Assessments%20DL/2014LTRA_
ERATTA.pdf.
77 Id.
78 PJM Interconnection, L.L.C., 151 FERC ¶
61,097, at n.58 (2015).
79 PJM Interconnection, L.L.C., Docket No. ER15–
1193–000 (March 6, 2015) Transmittal Letter at 11.
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pursuant to NERC’s Primary Frequency
Control Guideline (i.e., droop
characteristics not to exceed 5 percent,
and dead band settings not to exceed
±0.036 Hz)?
1.3. Ensure that the MW response
provided (when there is available
headroom) in response to frequency
deviations above or below the
governor’s dead band from 60 Hz is:
1.3.1. Sustained until system
frequency returns to within the
governor’s dead band setting?
1.3.2. Provided without undue delay
and responds in accordance with a
specified droop parameter?
2. What are the costs associated with
making a newly interconnecting
generation resource capable of
providing primary frequency response?
Specifically, what are the pieces of
equipment or software needed to
provide primary frequency response,
and what are the costs associated with
those pieces of equipment or software?
Are there significant differences
between synchronous and nonsynchronous resources in providing
primary frequency response, (e.g., the
type of equipment necessary)?
3. Regarding question (1) above, are
the governor control settings
recommended by NERC’s Primary
Frequency Control Guideline the
appropriate settings to include in the
pro forma LGIA and SGIA? Why or why
not?
4. Regarding new resources, including
non-synchronous resources, are there
physical, technical, or operational
limitations/concerns to promptly
providing sustained primary frequency
response in the direction necessary to
counteract under-frequency and overfrequency deviations? How should new
requirements account for such
limitations?
5. Are metrics or monitoring useful to
evaluate whether new resources:
5.1. Operate with governors (or
equivalent frequency control devices)
enabled?
5.2. Set governor control settings as
described in question (1) above?
5.3. Provide sustained MW response
(when the unit has available headroom
and system frequency deviates outside
of the dead band) that is in the direction
necessary to correct the frequency
deviation and responsive in accordance
with a specified droop parameter?
6. How would transmission providers
verify that new resources provide
adequate primary frequency response
performance?
6.1. What information is necessary in
order to facilitate performance
verification?
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6.2. What changes, if any, to existing
infrastructure (including, but not
limited to telemetry and software tools)
would be required in order to verify
primary frequency response
performance?
6.3. What limitations based on
resource type, if any, should be
considered when evaluating primary
frequency response performance?
7. How would transmission providers
ensure compliance with the new rules?
7.1. Are penalties appropriate to
ensure that new generating resources
adhere to the new requirements
described in question (1) above, and if
so, how should such penalties be
structured and implemented?
7.2. Are penalties appropriate only if
a resource receives compensation for
adhering to the new requirements
described in question (1) above?
B. New Primary Frequency Response
Requirements for Existing Resources
46. The Commission seeks comment
on how it might address the issue of
primary frequency response
performance in existing generators. As
discussed above, the Commission is
considering amendments to the pro
forma LGIA and SGIA that would apply
prospectively and only to new
generating resources and not the
existing generating fleet. However, the
Commission notes that NERC has also
expressed concerns related to the
primary frequency response
performance of the existing generating
fleet.
47. For example, in 2010, NERC
conducted a governor response survey
to gain insight into governor settings
from several turbine governors across
the three U.S. Interconnections.80
Analysis revealed a wide disparity in
the reported governor control settings.
For example, NERC found that several
generator owners or operators reported
dead bands between 0.05 Hz and 0.3 Hz,
which are wider than those prescribed
by ERCOT’S BAL–001–TRE–01 Regional
Standard or recommended by NERC’s
2015 Generator Governor Frequency
Response Industry Advisory 81 and
Primary Frequency Control Guideline.82
48. In February 2015, NERC issued an
Industry Advisory, which expressed its
determination that a significant portion
of generators within the Eastern
Interconnection utilize governor dead
bands or other control settings that
80 Frequency
Response Initiative Report at 87.
Generator Governor Frequency Response
Industry Advisory.
82 NERC Primary Frequency Control Guideline
Final Draft.
81 NERC
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either inhibit or prevent the provision of
primary frequency response.83
49. Furthermore, some generating
units have controls that withdraw
primary frequency response prior to the
initiation of secondary frequency
controls, which is a significant concern
in the Eastern Interconnection and a
somewhat smaller issue in the Western
Interconnection. These controls are
known as outer-loop controls to
distinguish them from more direct,
lower-level control of the generator
operations. Primary frequency response
withdrawal occurs when outer-loop
controls deliberately act to nullify a
generator’s governor response and
return the unit to operate at a predisturbance scheduled MW output. This
is especially problematic when it occurs
prior to the activation of secondary
response, and has the potential to
degrade the overall response of the
Interconnection and result in a
frequency that declines below the
original nadir. NERC has observed that
early withdrawal of primary frequency
response continues to occur within the
Eastern Interconnection.84
50. Furthermore, NERC’s Resources
Subcommittee has determined that the
majority of gas turbines operate in some
type of MW Set Point control mode.85
According to the NERC Resources
Subcommittee, the Eastern
Interconnection Initiative has uncovered
that in order for gas turbines to respond
in MW Set Point control mode, an
additional frequency algorithm has to be
installed.86 Moreover, NERC’s
Resources Subcommittee stated that
‘‘the net result is that the gas turbine
fleet that has been installed in the past
20+ years is not frequency responsive,
[which] has to be corrected.’’ 87 NERC
has also observed that in many
conventional steam plants, dead band
settings exceed the maximum ±0.036 Hz
dead band, and the resulting response is
squelched and not sustained.88
83 NERC Generator Governor Frequency Response
Industry Advisory.
84 NERC 2015 Frequency Response Annual
Analysis Report at vi (September 2015), https://
www.nerc.com/comm/OC/
RS%20Landing%20Page%20DL/Related%20Files/
2015_FRAA_Report_Final.pdf.
85 See News from SERC’s NERC Resources
Subcommittee Rep—Primary Frequency Response
at 1 (May 2015), https://www.serc1.org/docs/
default-source/outreach/communications/resourcedocuments/serc-transmission-reference/201505---st/
primary-frequency-response.pdf?sfvrsn=2. MW setpoint control mode automatically interrupts
governor response in order for a generating unit to
maintain a pre-disturbance dispatch.
86 Id.
87 Id.
88 See NERC Generator Governor Frequency
Response Advisory—Webinar Questions and
Answers at 1 (April 2015), https://www.nerc.com/
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51. As noted above, in December
2015, NERC’s Operating Committee
approved a 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 during major grid
events in order to stabilize and maintain
system frequency within allowable
limits.89 However, the Commission
notes that NERC’s Primary Frequency
Control Guideline is not mandatory and
enforceable and does not alter any
approved Reliability Standards.
52. In light of the above discussion,
the Commission seeks to further explore
issues regarding the provision of
primary frequency response by the
existing generation fleet and seeks
comment on the following questions:
1. Should the Commission implement
primary frequency response
requirements for existing resources, as
discussed above for new generators? If
so, what is an appropriate means of
doing so (e.g., changes to transmission
provider tariffs or improvements to
existing reliability standards)? How
would transmission providers ensure
that existing resources adhere to new
primary frequency response
requirements?
2. As noted above, some existing
generating units set dead bands wider
than those recommended by NERC’s
Primary Frequency Control Guideline,
and some units have control settings set
in a manner that results in the
premature withdrawal of primary
frequency response. Should the
Commission prohibit these practices? If
so, by what means?
3. What are the costs of retrofitting
existing units, including nonsynchronous resources, and with
specific reference to such factors as
equipment types and MW capacity, to
be capable of providing sustained
primary frequency response?
4. Regarding existing units, are there
physical, technical, or operational
limitations or concerns to promptly
providing sustained primary frequency
response in the direction necessary to
counteract under-frequency and overfrequency deviations?
pa/rrm/Webinars%20DL/Generator_Governor_
Frequency_Response_Webinar_QandA_April_
2015.pdf.
89 NERC Primary Frequency Control Guideline
Final Draft.
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C. Requirement to Provide and
Compensate for Primary Frequency
Response Service
53. Without the explicit requirement
to provide primary frequency response
or appropriate compensation for the
provision of such service, resource
owners may choose to disable or
otherwise reduce the provision of
primary frequency response from their
existing resources or not install the
equipment on their new resources.90
54. The Commission seeks
information on whether there is a need
to establish or modify procurement and
compensation mechanisms for primary
frequency response, and whether these
mechanisms will ensure that the
resulting rates are just and reasonable.
The Commission invites commenters to
share their overall views, including the
operational, technical and commercial
impacts that may result from mandates
to provide primary frequency response.
To that end, the Commission seeks
comment on the following questions:
1. Should all resources be required to
provide minimum levels of: (1) Primary
frequency response capability; and (2)
primary frequency response
performance in real-time?
1.1. ‘‘Capability’’ involves having a
turbine governor or equivalent
equipment that has the ability to sense
changes in system frequency, and is
enabled and set with appropriate
governor settings (e.g., droop and dead
band), and assuming capacity (or
‘‘headroom’’) has been set aside, the
physical ability to ramp the resource
quickly enough in order to provide
useful levels of primary frequency
response to help arrest the frequency
deviation.
1.2. ‘‘Performance’’ would involve
putting the ‘‘capability’’ into actual
service: i.e., actually operating the
resource with governors or equivalent
equipment enabled, ensuring that
governor controls (e.g., droop and dead
band) and other settings are properly set
and coordinated, such that when
capacity (or ‘‘headroom’’) has been set
aside, the unit promptly provides
sustained primary frequency response
during frequency excursions, until
system frequency returns to within the
governor’s dead band setting.
2. Is it necessary for every generating
resource to install the capability
necessary to provide primary frequency
90 IEEE, Interconnected Power System Response
to Generation Governing: Present Practice and
Outstanding Concerns (May 2007) (citing Cost of
Providing Ancillary Services from Power Plants—
Volume 1: A Primer, EPRI TR–1 07270–V1, 4161,
Final Report, March 1997), https://
resourcecenter.ieee-pes.org/pes/product/technicalreports/PESTR13.
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response? Or is it more appropriate for
balancing authorities to identify and
procure the amount of primary
frequency response service that they
need to meet their obligations under
Reliability Standard BAL–003–1 and the
optimum mix of resources to meet that
need?
2.1. To the extent that balancing
authorities are responsible for procuring
adequate primary frequency response
service, does the current framework for
blackstart provide a useful guide for
how primary frequency response service
could be procured?
2.2. Does the Commission’s recent
rulemaking allowing third-party sales of
frequency response services at market
based rates allow balancing authorities
to procure sufficient amounts of primary
frequency response as required by BAL–
003–1?
2.3. To the extent that balancing
authorities centrally optimize primary
frequency response, wherein an
algorithm optimizes in the operating
horizon the set of resources in which to
allocate primary frequency response
headroom: Should all newly
interconnecting resources be required to
install the necessary capability in these
areas? Can balancing authorities predict
far ahead of the operating horizon the
least-cost set of resources from which it
will optimize the provision of primary
frequency response?
2.4. Would the costs of requiring all
resources to have the capability to
provide primary frequency response be
significantly greater than the costs that
would result from an Interconnectionwide or balancing authority-wide
optimization of which generators should
be capable of providing primary
frequency response?
2.5. Would the costs of requiring all
new resources to enable and set their
governors, or equivalent equipment, to
be able to provide primary frequency
response in real-time be significantly
greater than the costs that would result
from an Interconnection-wide or
balancing authority-wide optimization
of which generators should provide
primary frequency response in realtime?
2.6. Please discuss the viability of
implementing an Interconnection-wide
optimization mechanism.
2.7. Would requiring every resource to
be capable of providing primary
frequency response result in overprocurement or inefficient investment
in primary frequency response
capability to the detriment of
customers?
2.8. Without rules to compel
performance, how would balancing
authorities ensure that the optimal set of
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resources chosen by an optimization
algorithm actually enable governor
controls with appropriate governor
settings so that they provide sustained
primary frequency response when
capacity (or ‘‘headroom’’) has been
reserved and frequency deviates outside
of their dead band settings?
3. If generation resources were
required to have minimum levels of
primary frequency response capability
or performance, should such resources
be compensated for providing primary
frequency response capability,
performance, or both? If so, why? If not,
why?
3.1. If payment is based on capacity
(or ‘‘headroom’’) that is set aside for
primary frequency response, how
should such a capacity payment be
structured and determined?
3.2. If payment is based on actual
performance, either alone or in
combination with a capacity-based
payment, please discuss possible rate
structures applicable to primary
frequency response performance.
3.3. Will a market price provide
resources with sufficient incentive to
invest in primary frequency response
capability and make the service
available to the balancing authority in
real-time, absent a requirement that
resources maintain the capability to
provide primary frequency response and
perform as required?
4. Currently, how do RTOs/ISOs
ensure that they have the appropriate
amount of primary frequency response
capability during operations?
4.1. Are resources contracted for
primary frequency response outside of
the market optimization and dispatch?
4.2. Alternatively, does the market
optimization and dispatch incorporate
primary frequency response in its
optimization?
5. Would it be appropriate for RTOs/
ISOs to create a product for primary
frequency response service?
5.1. Should this product be similar to
a capacity product for the procurement
of primary frequency response
capability from resources?
5.2. Should this product be similar to
other ancillary service products in
which certain resources would be
selected in the day-ahead or real-time
markets to provide primary frequency
response?
5.3. Are there benefits to cooptimizing the capacity (or
‘‘headroom’’) allocated on generating
units for primary frequency response
with the market optimization and
dispatch of RTOs/ISOs? If so, what are
the challenges associated with doing so?
6. Are there benefits to separating
Frequency Response Service under
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9191
Schedule 3 and creating a separate
ancillary service covering each
individually? If so, how should a new
pro forma Primary Frequency Response
Ancillary Service be structured?
7. When compensating for primary
frequency response, should
compensation be different inside and
outside of RTOs/ISOs?
8. What procurement requirements or
compensation mechanisms could be
used for primary frequency response
from stored energy resources? When
considering requirements or
compensation for stored energy
resources, how should possible
additional costs or other concerns be
addressed?
III. Comment Procedures
55. The Commission invites interested
persons to submit comments, and other
information on the matters, issues and
specific questions identified in this
notice. Comments are due April 25,
2016. 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.
56. 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.
57. 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.
58. 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.
IV. Document Availability
59. 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
FERC’s Home Page (https://
www.ferc.gov) and in FERC’s Public
Reference Room during normal business
hours (8:30 a.m. to 5:00 p.m. Eastern
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time) at 888 First Street NE., Room 2A,
Washington, DC 20426.
60. From FERC’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.
61. User assistance is available for
eLibrary and the FERC’s Web site during
normal business hours from FERC
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: February 18, 2016.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2016–03837 Filed 2–23–16; 8:45 am]
BILLING CODE 6717–01–P
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
[Docket No. RM11–6–000]
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Billing Procedures for Annual Charges
for Recompensing the United States
for the Use, Occupancy, and
Enjoyment of Federal Lands; Notice of
Statement of Annual Charges for the
Use of Government Lands for Fiscal
Year 2016
By this notice, the Commission states
that in accordance to the Final Rule
issued on January 17, 2013 1 the federal
lands fee schedule of per-acre rates have
been calculated for Fiscal Years (FY)
2016 through 2020. Pursuant to the
Final Rule, the Commission recalculates the federal lands fee schedule
every five years by using the per-acre
land values published in the National
Agricultural Statistics Service (NASS)
Census. The Commission established
the FY 2016 through FY 2020 federal
lands fee schedule based on data
published in the 2012 NASS Census. In
addition, the Commission determines a
state-specific reduction that removes the
value of irrigated lands on a state-bystate basis, plus a seven percent
reduction to remove the value of
buildings. An encumbrance factor of 50
1 Annual Charges for Use of Government Lands,
Final Rule, Order No. 774, 78 FR 5256 (January 25,
2013), 142 FERC Stats & Regs. ¶ 61,045 (2013).
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percent along with a rate of return of
5.77 percent are calculated with the peracre land values less the state-specific
reduction to derive at the individual
state/county per-acre federal land rates
assessed to hydropower projects.
The FY 2016 federal lands fee
schedule rates have significantly
increased in comparison to the FY 2015
federal lands fee schedule rates issued
on January 8, 2015 for a number of
hydropower projects located in multiple
states/counties. In particular,
hydropower projects located in the
Kenai Peninsula Area of Alaska land
rates increased by 71 percent in
comparison to land rates assessed in FY
2015. The FY 2016 increase of per-acre
land rates was mainly attributed to the
increase of per-acre land and building
values published in the 2012 NASS
Census. The per-acre land value for land
in the Kenai Peninsula Area was
increased from $1,328 in the 2007 NASS
Census to $2,423 in the 2012 NASS
Census. This increase along with
factoring in the state-specific reduction,
the 50 percent encumbrance factor, and
the 5.77 percent rate of return ultimately
resulted in a 71 percent increase of peracre land rates assessed to hydropower
projects located in the Kenai Peninsula
Area. In addition, per-acre land values
for San Bernardino County located in
California, Boulder and Clear Creek
Counties located in Colorado, and
Blaine County located in Idaho all
significantly increased as a result of the
2012 published NASS Census.
Conversely, the FY 2016 federal lands
fee schedule rates have significantly
decreased in comparison to the FY 2015
federal lands fee schedule rates issued
on January 8, 2015 for a number of
hydropower projects located in other
locations as a result of the decreased
per-acre land values published in the
2012 NASS Census. Specifically
hydropower projects occupying federal
lands in Alpine, Lake, and Riverside
Counties located in California, Aleutian
Islands Area located in Alaska, and
Grays Harbor County located in
Washington will receive as much as a 37
percent decrease in comparison to the
federal lands annual charges issued in
FY 2015.
If you have any questions regarding
this notice, please contact Steven
Bromberek at (202) 502–8001 or Norman
Richardson at (202) 502–6219.
Dated: February 18, 2016.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2016–03829 Filed 2–23–16; 8:45 am]
BILLING CODE 6717–01–P
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DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
Notice Revising Post-Technical
Conference Comment Schedule
Docket Nos.
PJM Interconnection, L.L.C ...
Consolidated Edison Company of New York, Inc. v.
PJM Interconnection, L.L.C.
Linden VFT, LLC v. PJM
Interconnection, L.L.C.
Delaware Public Service
Commission and Maryland
Public Service Commission
v. PJM Interconnection,
L.L.C.
PJM Interconnection, L.L.C ...
PJM Interconnection, L.L.C ...
ER15–2562–000,
ER15–2563–000.
EL15–18–001.
EL15–67–000.
EL15–95–000.
ER14–972–003.
ER14–1485–005,
Not Consolidated.
In an order dated November 24,
2015,1 the Commission found that the
assignment of cost allocation for the
projects in the filings and complaints
listed in the caption using PJM’s
solution-based distribution factor
(DFAX) cost allocation method had not
been shown to be just and reasonable
and may be unjust, unreasonable, or
unduly discriminatory or preferential.
The Commission directed its staff to
establish a technical conference to
explore both whether there is a
definable category of reliability projects
within PJM for which the solution-based
DFAX cost allocation method may not
be just and reasonable, such as projects
addressing reliability violations that are
not related to flow on the planned
transmission facility, and whether an
alternative just and reasonable ex ante
cost allocation method could be
established for any such category of
projects.
The technical conference was held on
January 12, 2016. At the technical
conference, staff indicated that it would
establish a schedule for post-technical
conference comments after reviewing
the technical conference transcript. On
February 9, 2016 a technical conference
transcript was place in the abovereferenced dockets, and a post-technical
conference comment schedule was
established. On February 18, 2016, an
errata transcript of the February 9, 2016
transcript was placed in the dockets.
The schedule for post-technical
conference comments is revised
accordingly.
Post-technical conference comments,
not to exceed 20 pages, are due on or
before March 9, 2016.
1 PJM Interconnection, L.L.C., et al., 153 FERC ¶
61,245 (2015).
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]]>Agencies
[Federal Register Volume 81, Number 36 (Wednesday, February 24, 2016)]
[Notices]
[Pages 9182-9192]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-03837]
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
[Docket No. RM16-6-000]
Essential Reliability Services and the Evolving Bulk-Power
System--Primary Frequency Response
AGENCY: Federal Energy Regulatory Commission, Energy.
ACTION: Notice of Inquiry.
-----------------------------------------------------------------------
SUMMARY: In this Notice of Inquiry, the Federal Energy Regulatory
Commission (Commission) seeks comment on the need for reforms to its
rules and regulations regarding the provision and compensation of
primary frequency response.
DATES: Comments are due April 25, 2016.
ADDRESSES: You may submit comments, identified by docket number and in
accordance with the requirements posted on the Commission's Web site,
https://www.ferc.gov. Comments may be submitted by any of the following
methods:
Agency Web site: Documents created electronically using
word processing software should be filed in native applications or
print-to-PDF format and not in a scanned format, at https://www.ferc.gov/docs-filing/efiling.asp.
Mail/Hand Delivery: Those unable to file electronically
must 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 Inquiry (NOI), the Commission seeks comment on
the need for reforms to its rules and regulations regarding the
provision and compensation of primary frequency response. In recent
years, the nation's electric supply portfolio has transformed to a
point where fewer resources may now be providing primary frequency
response than when the Commission considered this issue in other
relevant proceedings. As discussed below, in light of the changing
resource mix and other factors, it is reasonable to expect this trend
to continue. Considering the significance of primary frequency response
to the reliable operation of the Bulk-Power System,\1\ the Commission
seeks input on whether and what action is needed to address the
provision and compensation of primary frequency response.
---------------------------------------------------------------------------
\1\ 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).
---------------------------------------------------------------------------
2. Specifically, the Commission seeks comment on whether amendments
to the pro forma Large Generator Interconnection Agreement (LGIA) and
Small Generator Interconnection Agreement (SGIA) are warranted to
require all new generation resources to have frequency response
capabilities as a precondition of interconnection. The Commission also
seeks comment on the performance of existing resources and whether
primary frequency response requirements for these resources are
warranted. Further, the Commission seeks comment on the requirement to
provide and compensate for primary frequency response.
[[Page 9183]]
I. Background
A. Technical Overview: The Nature and Operation of Frequency Response
3. Reliably operating an Interconnection \2\ requires maintaining
balance between generation and load so that frequency remains within
predetermined boundaries around a scheduled value (60 Hz in the United
States). Interconnections occasionally experience system contingencies
(e.g., the loss of a large generator) that disrupt the balance between
generation and load. These contingencies result in frequency deviations
that can potentially cause under frequency load shedding (UFLS),
additional generation tripping, or cascading outages.\3\ Consequently,
some generators within an Interconnection automatically deploy
frequency control actions, including inertial response and primary
frequency response, during disturbances to arrest and stabilize
frequency deviations. The reliability of the Bulk-Power System depends
in part on the operating characteristics of generating resources that
balancing authorities \4\ commit to serve load. However, not all
generating resources provide frequency support services, which are
essential to maintaining the reliability and stability of the Bulk-
Power System.\5\
---------------------------------------------------------------------------
\2\ An Interconnection is a geographic area in which the
operation of Bulk-Power System components is synchronized. In the
continental United States, there are three Interconnections, namely
the Eastern, Electric Reliability Council of Texas (ERCOT), 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. Automatic Underfrequency Load Shedding and
Load Shedding Plans Reliability Standards, Notice of Proposed
Rulemaking, 137 FERC ] 61,067 (2011).
\4\ The North American Electric Reliability Corporation's (NERC)
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.''
\5\ As discussed below, NERC Reliability Standard BAL-003-1 has
requirements related to frequency response, but it is applicable to
balancing authorities and not individual generating resources.
---------------------------------------------------------------------------
4. Frequency response is a measure of an Interconnection's ability
to arrest and stabilize frequency deviations within pre-determined
limits following the sudden loss of generation or load. Frequency
response is affected by the collective responses of generation and load
resources throughout the entire Interconnection. Inertial response,
primary frequency response, and secondary frequency response all
contribute to stabilizing the Bulk-Power System by correcting frequency
deviations.
5. Inertial response, or system inertia, involves the release or
absorption of kinetic energy by the rotating masses of online
generation and load within an Interconnection, and is the result of the
coupling between the rotating masses of synchronous generation and load
and the electric system.\6\ An Interconnection's inertial response
influences how fast frequency drops after the loss of generation and
how fast it rises after a reduction of load. The less system inertia
there is, the faster the rate of change of frequency \7\ during
disturbances. An adequate amount of system inertia is important since
following the sudden loss of generation, inertia serves to reduce the
rate of change of frequency, allowing time for primary frequency
response actions to arrest the frequency deviation and stabilize the
power system.
---------------------------------------------------------------------------
\6\ See, e.g., Use of Frequency Response Metrics to Assess the
Planning and Operating Requirements for Reliable Integration of
Variable Renewable Generation, Ernest Orlando Lawrence Berkeley
National Laboratory, at 13-14 (December 2010), available at: https://energy.lbl.gov/ea/certs/pdf/lbnl-4142e.pdf (LBNL Frequency Response
Metrics Report).
\7\ Rate of change of frequency is mainly a function of the
magnitude of the loss of generation (or load) and system inertia and
is measured in Hz/second.
---------------------------------------------------------------------------
6. Primary frequency response, net of changes in generation real
power (MW) output and power consumed by load in response to a frequency
deviation, is the first stage of overall frequency control, begins
within seconds after the frequency changes, and is critical to the
reliable operation of the Bulk-Power System.\8\ Primary frequency
response is 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 due to changes
in system frequency. Primary frequency response actions are intended to
arrest the frequency deviation until it reaches the minimum frequency,
or nadir.\9\ An important goal for system planners and operators is for
the frequency nadir, during large disturbances, to remain above the
first stage of firm UFLS set points within an Interconnection. The
time-frame to arrest frequency deviations typically ranges from five to
15 seconds, depending on the Interconnection.
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\8\ See, e.g., LBNL Frequency Response Metrics Report at 15-16.
\9\ The point at which the frequency decline is arrested
(following the sudden loss of generation) is called the frequency
nadir, and represents the point in which the net primary frequency
response (MW) output from all generating units and the decrease in
power consumed by the load within an Interconnection matches the net
initial MW loss of generation.
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7. Secondary frequency response involves changes to the MW output
of resources on automatic generation control (e.g., regulation
resources) that respond to dispatch instructions.\10\ Secondary
frequency response actions usually begin after 30 seconds or more
following a contingency, and can take 5 minutes or more to restore
system frequency to its scheduled value.
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\10\ See e.g., LBNL Frequency Response Metrics Report at 9-11.
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B. Evolving Generation Resource Mix
8. The nation's generation resource mix is undergoing a
transformation that includes the retirement of baseload, synchronous
units, with large rotational inertia. The changing resource mix also
includes the integration of more distributed generation, demand
response, and natural gas resources, and the rapid expansion of
variable energy resources (VERs) \11\ such as wind and solar.\12\
Several factors, such as existing and proposed federal and state
environmental regulations, renewable portfolio standards, tax
incentives, and low natural gas prices, have driven these developments.
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\11\ For the purposes of this proceeding, the term Variable
Energy Resource refers to 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. This includes, for example, wind, solar thermal and
photovoltaic, and hydrokinetic generating facilities. See
Integration of Variable Energy Resources, Order No. 764, FERC Stats.
& Regs. ] 31,331 at n. 1 (2012), order on reh'g and clarification,
Order No. 764-A, 141 FERC ] 61,232 (2012), order on clarification
and reh'g, Order No. 764-B, 144 FERC ] 61,222 (2013).
\12\ The Solar Energy Industries Association (SEIA) recently
reported that more than 50 percent of newly installed electric
generating capacity in the U.S. came from solar generation in the
first quarter of 2015. See SEIA Solar Market Insight Report 2015 Q1
(2015), https://www.seia.org/research-resources/solar-market-insight-report-2015-q1.
---------------------------------------------------------------------------
9. During 2015, natural gas-fired generation surpassed coal as the
predominant fuel source for electric generation, and is now the leading
fuel type for capacity additions.\13\ In addition, NERC recently
determined that there has been almost 50 GW of baseload (e.g., coal,
nuclear, petroleum, and natural gas) retirements since 2011.\14\
---------------------------------------------------------------------------
\13\ See NERC 2015 Long Term Reliability Assessment at 1
(December 2015), https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2015LTRA%20-%20Final%20Report.pdf.
\14\ See NERC 2015 Summer Reliability Assessment at 5 (May
2015), https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2015_Summer_Reliability_Assessment.pdf
.
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10. In addition, between 2014 and 2015, all three U.S.
Interconnections have experienced growth in the installed nameplate
capacity of wind and solar generation. For example, as illustrated by
the figure below, NERC
[[Page 9184]]
has observed that the three Interconnections collectively added
approximately 11.1 GW of wind and 1.73 GW of solar generation between
2014 and 2015.\15\ More specifically, in 2015: (1) The Eastern
Interconnection had 37.6 GW of wind and 1.6 GW of solar capacity,
representing a growth rate of 12 percent and 116 percent over the
respective 2014 levels of 33.5 GW and 0.73 GW;\16\ (2) ERCOT had 14.7
GW of wind and 0.18 GW of solar, representing a growth rate of 29
percent and 50 percent over the respective 2014 levels of 11.4 GW and
0.12 GW;\17\ and (3) Western Interconnection had 24.8 GW of wind and
8.4 GW of solar, representing a growth rate of 17 percent and 11
percent over the respective 2014 levels of 21.1 GW and 7.6 GW.\18\
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\15\ NERC 2015 Summer Reliability Assessment, Table 3 at page 7.
\16\ Id.
\17\ Id.
\18\ Id.
[GRAPHIC] [TIFF OMITTED] TN24FE16.030
11. The changing generation resource mix has the potential to
reduce the inertial response within some Interconnections, as VERs do
not contribute to inertia unless they are specifically designed to do
so. For example, solar photovoltaic resources have no rotating mass and
thus no rotational inertia. Similarly, while wind turbines have a
rotating mass, power converters that interconnect modern wind turbines
decouple the rotation of their turbines from the grid. As such, modern
wind turbines do not contribute to the system's inertia unless
specifically configured to do so.\19\ Therefore, increased numbers of
VERs, in conjunction with significant retirements of large conventional
resources with large rotational inertia, have the potential to reduce
system inertia.
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\19\ See, e.g., General Electric WindINERTIA Control Fact Sheet
(2009), https://site.ge-energy.com/prod_serv/products/renewable_energy/en/downloads/GEA17210.pdf.
---------------------------------------------------------------------------
12. In addition, VERs do not provide primary frequency response
unless specifically configured to do so. Furthermore, since VERs
typically have low marginal costs of production, they would likely not
be dispatched in a manner necessary to provide primary frequency
response, since the provision of primary frequency response involves
the reservation of capacity (or ``headroom'') in order for a resource
to automatically increase its MW output in response to drops in system
frequency. Therefore, there is a significant risk that, as conventional
synchronous resources retire or are displaced by increased numbers of
VERs that do not typically have primary frequency response
capabilities, the net amount of frequency responsive generation online
will be reduced.\20\
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\20\ Non-synchronous generators such as VERs (e.g., wind and
solar resources) produce electricity that is not synchronized to the
electric grid (i.e., direct current (DC) power or alternating
current (AC) power at a frequency other than 60 hertz). Inverters
convert non-synchronized AC or DC power into synchronized AC power
that can be transmitted on the transmission system. These resources
do not operate in the same way as conventional generators and
respond differently to network disturbances.
---------------------------------------------------------------------------
13. The combined impacts of lower system inertia and lower
frequency responsive capability online may adversely affect reliability
during disturbances because lower system inertia results in more rapid
frequency deviations during disturbances. This, in turn, may result in
lower frequency nadirs, particularly if the primary frequency
capability online is not sufficiently fast. This is a potential
reliability concern because, as the frequency nadir lowers, it
approaches the Interconnection's UFLS trip setting, which could result
in the loss of load and additional generation across the
Interconnection.
14. These developments and their potential impacts could challenge
system operators in maintaining reliability. The Commission believes
that a substantial body of evidence has emerged warranting
consideration of possible actions to ensure that resources capable of
providing primary frequency
[[Page 9185]]
response are adequately maintained as the nation's resource mix
continues to evolve.
15. 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.\21\ The Task Force focused on three essential
reliability services: frequency support, ramping capability, and
voltage support.\22\
---------------------------------------------------------------------------
\21\ 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 (April 2014), https://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/Scope_ERSTF_Final.pdf.
\22\ Essential Reliability Services Task Force Measures Report
at 22 (December 2015), https://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/ERSTF%20Framework%20Report%20-%20Final.pdf.
---------------------------------------------------------------------------
16. The Task Force considered the seven ancillary services \23\
adopted by the Commission in Order Nos. 888 \24\ and 890 \25\ as a
subset of the essential reliability services that may need to be
augmented by additional services as the Bulk-Power System
characteristics change. However, the Task Force did not intend to
recommend new reliability standards or propose actions to alter the
existing suite of ancillary services.\26\ Instead, its focus was on
educating and informing industry and other stakeholders about essential
reliability services, developing measures and industry best practices
for tracking essential reliability services, and developing
recommendations to ensure that essential reliability services continue
to be provided as the nation's generation resource mix evolves.\27\
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\23\ The seven ancillary services 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.
\24\ 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).
\25\ 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).
\26\ NERC Essential Reliability Services Task Force Scope
Document at 2.
\27\ Id.
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17. The reliability of the Bulk-Power System will be increasingly
dependent upon the operational characteristics of natural gas and
renewable generating units, as these types of resources are expected to
comprise an increasing percentage of the future generation resource
mix. The Task Force stated that ``the reliability of the electric grid
depends on the operating characteristics of the replacement
resources.'' \28\ NERC observed that ``wind, solar, and other variable
energy resources that are an increasingly greater share of the Bulk-
Power System provide a significantly lower level of essential
reliability services than conventional generation.'' \29\ The Task
Force concluded that it is prudent and necessary to ensure that primary
frequency capabilities are present in the future generation resource
mix, and recommends that all new generators support the capability to
manage frequency.\30\
---------------------------------------------------------------------------
\28\ Essential Reliability Services Task Force Measures Report
at iv.
\29\ See NERC State of Reliability 2015 Report at 16 (May 2015),
https://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%20DL/2015%20State%20of%20Reliability.pdf.
\30\ Essential Reliability Services Task Force Measures Report
at vi.
---------------------------------------------------------------------------
18. Contributing to the concerns associated with the nature and
operational characteristics of the evolving resource mix is the
uncertainty whether a resource configured to provide primary frequency
response is willing and able to offer such a service when called upon
to do so. While almost all existing synchronous resources and some non-
synchronous resources have governors or equivalent control equipment
capable of providing primary frequency response, generator owners and
operators can independently decide whether units provide primary
frequency response.\31\
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\31\ 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 MW output due to
variations in system frequency. A governor also has a dead band
which establishes a minimum frequency deviation (from nominal) that
must be exceeded in order for the governor to act. Example droop and
dead band settings are 5 percent and 0.036 Hz,
respectively.
---------------------------------------------------------------------------
19. For example, at present, it is possible for a generator owner/
operator to block or disable the governor or to set a wide dead band
setting. A wide dead band setting can result in a unit not providing
primary frequency response for most frequency deviations. As discussed
more fully below, in February 2015, NERC issued an Industry Advisory
which determined that a significant portion of generators within the
Eastern Interconnection utilize dead bands or governor control settings
that either inhibit or prevent the provision of primary frequency
response.\32\ In response to this issue and other concerns, NERC's
Operating Committee recently approved a 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.\33\
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\32\ NERC Generator Governor Frequency Response Industry
Advisory (February 2015), https://www.nerc.com/pa/rrm/bpsa/Alerts%20DL/2015%20Alerts/NERC%20Alert%20A-2015-02-05-01%20Generator%20Governor%20Frequency%20Response.pdf.
\33\ See NERC Primary Frequency Control Guideline Final Draft
(December 2015), https://www.nerc.com/comm/OC/Reliability%20Guideline%20DL/Primary_Frequency_Control_final.pdf.
See also NERC Operating Committee Meeting Minutes (January 2016),
https://www.nerc.com/comm/OC/AgendasHighlightsMinutes/Operating%20Committee%20Minutes%20-%20Dec%2015-16%202015-Final.pdf.
---------------------------------------------------------------------------
20. NERC's State of Reliability Report for 2015 explained that the
three U.S. Interconnections currently exhibit stable frequency response
performance above their Interconnection Frequency Response
Obligations.\34\ However, NERC has pointed out a historic decline in
frequency response performance in both the Western and Eastern
Interconnections.\35\ NERC identified several key reasons for the
decline, mainly tied to the primary frequency response performance of
generators.\36\
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\34\ NERC State of Reliability Report 2015 at 9 (May 2015). See
https://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%20DL/2015%20State%20of%20Reliability.pdf. Reliability Standard BAL-003-1
establishes Interconnection Frequency Response Obligations that are
designed to require sufficient frequency response for each
Interconnection to arrest frequency declines even for severe, but
possible, contingencies.
\35\ See NERC Frequency Response Initiative Industry Advisory--
Generator Governor Frequency Response at slide 10 (April 2015),
https://www.nerc.com/pa/rrm/Webinars%20DL/Generator_Governor_Frequency_Response_Webinar_April_2015.pdf. See
also Review of the Recent Frequency Performance of the Eastern,
Western and ERCOT Interconnections, Ernest Orlando Lawrence Berkeley
National Laboratory, at pp xiv-xv (December 2010), https://energy.lbl.gov/ea/certs/pdf/lbnl-4144e.pdf.
\36\ See NERC Frequency Response Initiative Report: The
Reliability Role of Frequency Response (October 2012), https://www.nerc.com/docs/pc/FRI_Report_10-30-12_Master_w-appendices.pdf
(Frequency Response Initiative Report).
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C. Prior Commission and Industry Actions
21. In this proceeding, the Commission seeks comment on the need
[[Page 9186]]
for reforms to its rules and regulations regarding the provision of
primary frequency response. This section offers an overview of
Commission and industry action to date related to frequency response to
provide the context for the consideration of what, if any, actions the
Commission should take to ensure that adequate frequency response is
available to maintain grid reliability.
22. In April 1996, the Commission issued Order No. 888, to address
undue discrimination in transmission service by requiring all public
utilities to provide open access transmission service consistent with
the terms of a pro forma Open Access Transmission Tariff (OATT).\37\
The pro forma OATT sets forth the terms of transmission service
including, among other things, the provision of ancillary services.
Additionally, the Commission adopted six ancillary services stating
they are ``needed to accomplish transmission service while maintaining
reliability within and among control areas affected by the transmission
service.'' \38\ The ancillary service involved in this proceeding is
Regulation and Frequency Response Service, found in Schedule 3 of the
pro forma OATT.
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\37\ Order No. 888, FERC Stats. & Regs. ] 31,036.
\38\ Id. at 31,705.
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23. In July 2003, the Commission issued Order No. 2003, which
revised the pro forma OATT to include a pro forma LGIA, which applies
to interconnection requests of large generators (i.e., generators
larger than 20 MW).\39\ While the pro forma LGIA adopted standard
procedures and a standard agreement for the interconnection of large
generating facilities, it was ``designed around the needs of large
synchronous generators.'' \40\ The Commission also added a blank
Appendix G (Requirements of Generators Relying on Newer Technologies)
to the LGIA to serve as a means by which to apply interconnection
requirements specific for generators relying on newer technologies,
such as wind generators.\41\
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\39\ Standardization of Generator Interconnection Agreements and
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146, app. 6
(LGIP), app. C (LGIA) (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).
\40\ Order No. 2003-A, FERC Stats. & Regs. ] 31,160 at P 407 &
n.85.
\41\ Id.
---------------------------------------------------------------------------
24. In May 2005, the Commission issued Order No. 2006, which
required all public utilities to adopt standard terms and conditions
for new interconnecting small generators (i.e., those no larger than 20
MW) under a pro forma SGIA.\42\
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\42\ 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).
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25. The Commission recently issued a notice of proposed rulemaking
to revise the pro forma LGIA and SGIA to eliminate the exemption for
wind generators and other non-synchronous generators regarding reactive
power requirements.\43\ The proposed rule proposes to require all newly
interconnecting generators, both synchronous and non-synchronous, to
provide reactive power.
---------------------------------------------------------------------------
\43\ Reactive Power Requirements for Non-Synchronous Generation,
153 FERC ] 61,175 (2015).
---------------------------------------------------------------------------
26. Although the Commission has previously included technical
requirements for generators in the LGIA and Large Generator
Interconnection Procedures (LGIP),\44\ both the pro forma LGIA and SGIA
are silent with respect to primary frequency response requirements.
---------------------------------------------------------------------------
\44\ For example, in Order Nos. 661 and 661-A, the Commission
adopted standard procedures and technical requirements related to
low voltage ride thru and power factor design criteria for the
interconnection of large wind plants, and required all public
utilities that own, control, or operate facilities for transmitting
electric energy in interstate commerce to append Appendix G to their
LGIPs and LGIAs in their OATTs to include these requirements.
Interconnection for Wind Energy, Order No. 661, FERC Stats. & Regs.
] 31,186, order on reh'g, Order No. 661-A, FERC Stats. & Regs. ]
31,198 (2005).
---------------------------------------------------------------------------
27. In a final rule issued on January 16, 2014, the Commission
approved Reliability Standard BAL-003-1, which establishes frequency
response requirements for balancing authorities.\45\ Reliability
Standard BAL-003-1 established Interconnection Frequency Response
Obligations that prescribe the minimum frequency response that must be
maintained by an Interconnection. The purpose of the Interconnection
Frequency Response Obligation is to maintain the minimum frequency
(nadir) above UFLS set points following the largest contingency of the
Interconnection as defined by the resource contingency criteria in BAL-
003-1. Each balancing authority is assigned a Frequency Response
Obligation \46\ that is a proportionate share of the Interconnection
Frequency Response Obligation, and is based on its annual generation
and load.\47\ Requirement R1 of BAL-003-1 requires each balancing
authority to achieve an annual Frequency Response Measure that equals
or exceeds its Frequency Response Obligation. The Frequency Response
Measure is the median value of a balancing authority's frequency
response performance during selected events over the course of a
year.\48\ Requirement R1 of BAL-003-1 becomes effective on April 1,
2016, and compliance begins on December 1, 2016.
---------------------------------------------------------------------------
\45\ Frequency Response and Frequency Bias Setting Reliability
Standard, Order No. 794, 146 FERC ] 61,024 (2014). Reliability
Standards proposed by NERC are submitted to the Commission for
approval pursuant to section 215(d) of the FPA; 16 U.S.C. 824o(d).
\46\ NERC's Glossary of Terms defines Frequency Response
Obligation as ``[t]he balancing authority's share of the required
Frequency Response needed for the reliable operation of an
Interconnection.''
\47\ The Interconnection Frequency Response Obligation and
Frequency Response Obligation are expressed in MW per 0.1 Hertz (MW/
0.1 Hz).
\48\ Attachment A of BAL-003-1. NERC will identify between 20 to
35 events annually in each Interconnection for calculating the
Frequency Response Measure. See also Procedure for ERO Support of
Frequency Response and Frequency Bias Setting Standard, (November
30, 2012), https://www.nerc.com/pa/Stand/Project%20200712%20Frequency%20Response%20DL/Procedure_Clean_20121130.pdf.
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28. Although Reliability Standard BAL-003-1 requires sufficient
frequency response from balancing authorities, on average, to maintain
Interconnection frequency, it does not require generators to provide
primary frequency response. In the rulemaking in which the Commission
approved Reliability Standard BAL-003-1, some commenters expressed
concern that the standard does not address the availability of
generator resources to provide primary frequency response or the
premature withdrawal \49\ of primary frequency response. In Order No.
794, the Commission directed NERC to submit a report by July 2018
analyzing the availability of resources for each balancing authority
and Frequency Response Sharing Group \50\ to meet their Frequency
Response Obligation.\51\ Furthermore, the Commission stated that, if
NERC learns that balancing authorities are experiencing difficulty in
procuring sufficient resources to satisfy their Frequency Response
Obligations,
[[Page 9187]]
NERC should immediately report it to the Commission with appropriate
recommendations for mitigation.\52\
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\49\ NERC has stated that ``[w]ithdrawal of primary frequency
response is an undesirable characteristic associated most often with
digital turbine-generator control systems using setpoint output
targets for generator output. These are typically outer-loop control
systems that defeat the primary frequency response of the governors
after a short time to return the unit to operating at a requested MW
output.'' See Order No. 794, 146 FERC ] 61,024 at P 65 (citing
NERC's Frequency Response Initiative Report).
\50\ NERC's Glossary of Terms defines a Frequency Response
Sharing Group as a ``group whose members consist of two or more
Balancing Authorities that collectively maintain, allocate, and
supply operating resources required to jointly meet the sum of the
Frequency Response Obligations of its members.''
\51\ Order No. 794, 146 FERC ] 61,024 at P 60.
\52\ Id. P 63.
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29. Additionally, in Order No. 794, the Commission stated that the
nature and extent of the problems that could result from the premature
withdrawal of primary frequency response, and how best to address them,
will be better understood after NERC and balancing authorities have
more experience with Reliability Standard BAL-003-1.\53\ The Commission
also stated that the need to take action regarding the premature
withdrawal of primary frequency response, including requiring load
controllers to include a frequency bias term to sustain frequency
response or otherwise modifying Reliability Standard BAL-003-1, should
be decided after we have actual experience with the Reliability
Standard.\54\
---------------------------------------------------------------------------
\53\ Id. P 75.
\54\ Id. P 76.
---------------------------------------------------------------------------
30. In light of the ongoing evolution of the nation's generation
resource mix, and other factors, such as NERC's Generator Governor
Industry Advisory released in February 2015, the Commission believes
that it is prudent to take a proactive approach to better understand
the issues related to primary frequency response performance and
determine what additional actions beyond Reliability Standard BAL-003-1
may be appropriate. Thus, the Commission is proceeding with a Notice of
Inquiry at this time rather than waiting until NERC submits a report in
2018.
31. In the absence of national primary frequency response
requirements applicable to individual generating resources, some areas,
including ERCOT, ISO New England Inc. (ISO-NE), and PJM
Interconnection, L.L.C. (PJM), have implemented regional requirements
for individual generating resources within their regions in order to
maintain reliability.
32. For example, the Commission accepted Texas Reliability Entity
Inc.'s Regional Reliability Standard BAL-001-TRE-01 (Primary Frequency
Response in the ERCOT Region) as mandatory and enforceable, which
places requirements on generator owners and operators with respect to
the provision of primary frequency response within the ERCOT
region.\55\ In particular, BAL-001-TRE-01 requires generator owners to
operate each generating unit/generating facility that is connected to
the interconnected transmission system with the governor in service and
responsive to frequency when the generating unit/generating facility is
online and released for dispatch, and to promptly notify the balancing
authority of any change in governor status.\56\ Additionally, BAL-001-
TRE-01 requires generator owners to set specified governor dead band
and droop parameters.\57\ Moreover, BAL-001-TRE-01 requires generator
owners to provide minimum initial and sustained primary frequency
response performance.\58\ NERC recently noted that ERCOT experienced a
significant improvement in its frequency response performance as
generators within its region adjusted their governor settings for
compliance with BAL-001-TRE-01.\59\
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\55\ North American Electric Reliability Corporation, 146 FERC ]
61,025 (2014). The requirements of BAL-001-TRE-01 help to ensure
that generation and load remain balanced--or are quickly restored to
balance--in the ERCOT Interconnection so that system frequency is
restored to stability and near normal frequency even after a
significant event occurs on the system. In Order No. 693, the
Commission approved a regional difference for the ERCOT
Interconnection from Reliability Standard BAL-001-0, allowing ERCOT
to be exempt from Requirement R2, and found that ERCOT's approach to
frequency response under its own market protocols appeared to be
more stringent than Requirement R2. Order No. 693, FERC Stats. &
Regs. ] 31,242 at PP 313-315.
\56\ Reliability Standard BAL-001-TRE-01, at Requirements R7 and
R8.
\57\ Reliability Standard BAL-001-TRE-01, at Requirement R6.
\58\ Reliability Standard BAL-001-TRE-01, at Requirements R9 and
R10.
\59\ NERC 2014 Frequency Response Annual Analysis Report at 6
(February 2015), https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Final_Info_Filing_Freq_Resp_Annual_Report_03202015.pdf. See also
Table 3 at 6.
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33. ISO-NE requires each generator within its region with a
capability of ten MW or more, including renewable resources, to operate
with a functioning governor with specified dead band and droop
settings, and to also ensure that the provision of primary frequency
response is not inhibited by the effects of outer-loop controls.\60\
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\60\ Section I of ISO-NE's Operating Procedure No. 14--Technical
Requirements for Generators, Demand Resources, Asset Related Demands
and Alternative Technology Regulation Resources, https://www.iso-ne.com/rules_proceds/operating/isone/op14/op14_rto_final.pdf.
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34. PJM has pro forma interconnection agreements that obligate
interconnection customers within its region to abide by all PJM rules
and procedures pertaining to generation and transmission, including
rules and procedures set forth in the PJM Manuals.\61\ PJM requires
large, conventional generators to operate on unrestricted governor
control to assist in maintaining Interconnection frequency, and
recently established specified governor dead band and droop
requirements for all generating resources (excluding nuclear units)
with a gross plant/facility aggregate nameplate rating greater than 75
MVA.\62\ In addition, PJM recently added new interconnection
requirements for interconnection customers entering its queue after May
2015 and seeking to interconnect non-synchronous generators, including
wind generators, to use ``enhanced inverters'' with the capability to,
among other things, provide primary frequency response.\63\ PJM stated
that the installed capacity of VERs in its region is expected to
increase to approximately 15 GW by the 2016-17 delivery year, and that
it has an additional 25 GW of VERs in its interconnection queue.\64\
PJM expressed a need for VERs to install the capability to
automatically reduce or increase their real power output in order to
respond to a variety of system conditions, including high or low
frequencies. PJM also stated that this capability will provide
flexibility in responding to transmission system events using all
available resources which, according to PJM, will be increasingly
important as VERs displace synchronous generators that have these
capabilities.\65\
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\61\ PJM Tariff, Attachment O Sec. 8.0.
\62\ PJM Manual 14D.
\63\ PJM Interconnection, L.L.C., 151 FERC ] 61,097, at n.58
(2015).
\64\ PJM Interconnection, L.L.C., Transmittal Letter, Docket No.
ER15-1193-000, at 2 (filed Mar. 6, 2015).
\65\ Id. at 11.
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D. Compensation for Primary Frequency Response Service
35. This section offers an overview of Commission and industry
action to date related to compensation for primary frequency response.
At present, there are few, if any, entities receiving compensation for
selling primary frequency response as a stand-alone product, and there
are no current rates applicable to sales of primary frequency response
alone. However, several options for transactions involving primary
frequency response have been developed. Transmission providers may sell
primary frequency response service in combination with regulation
service under the bundled pro forma OATT Schedule 3 product, Regulation
and Frequency Response Service.\66\
[[Page 9188]]
Schedule 3 in the pro forma OATT in Order Nos. 888 \67\ and 890 \68\
permits jurisdictional transmission providers to outline their rates
for this regulation and frequency response service through a filing
under FPA section 205. Schedule 3 charges are cost-based rates paid by
transmission customers to the transmission provider. Additionally,
Order No. 784 made it possible for third-party sellers to offer
Schedule 3 service to the transmission provider at a rate up to the
published Schedule 3 rate, or at rates that result from an appropriate
competitive solicitation.\69\ Such third-party sales could involve any
combination of regulation and primary frequency response services,
including unbundled primary frequency response service by itself.
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\66\ Regulation service is different than primary frequency
response because regulation resources respond to automatic
generation control signals, which responds to Area Control Error.
Regulation is centrally coordinated by the balancing authority.
Primary frequency response, in contrast, is autonomous and is not
centrally coordinated. Schedule 3 lumps these different services
together, despite their differences. The Commission in Order No. 888
found that ``while the services provided by Regulation Service and
Frequency Response Service are different, they are complementary
services that are made available using the same equipment. For this
reason, we believe that Frequency Response Service and Regulation
Service should not be offered separately, but should be offered as
part of one service.'' Order No. 888, FERC Stats. & Regs. ] 31,036,
at PP 212-213 (1996).
\67\ Order No. 888, FERC Stats. & Regs. ] 31,036.
\68\ Order No. 890, FERC Stats. & Regs. ] 31,241.
\69\ Third-Party Provision of Ancillary Services; Accounting and
Financial Reporting for New Electric Storage Technologies, Order No.
784, FERC Stats. & Regs. ] 31,349, at PP 6-7 (2013), order on
clarification, Order No. 784-A, 146 FERC ] 61,114 (2014).
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36. Finally, in Order No. 819, the Commission revised its
regulations to foster competition in the sale of primary frequency
response service.\70\ In the final rule, the Commission approved the
sale of primary frequency response service at market-based rates by
entities that qualify for market-based rate authority for sales of
energy and capacity to any willing buyer. Order No. 819 focused on how
jurisdictional entities can qualify for market-based rates for primary
frequency response service in the context of voluntary bilateral sales,
and did not place any limits on the types of transactions available to
procure primary frequency response service; they may be cost-based or
market-based, bundled with other services or unbundled, and inside or
outside of organized markets.\71\ Order No. 819 did not require any
entity to purchase primary frequency response from third parties or
develop an organized market for primary frequency response.\72\
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\70\ Third-Party Provision of Primary Frequency Response
Service, Order No. 819, 153 FERC ] 61,220 (2015).
\71\ Id. P 13.
\72\ Id. P 37. The Commission denied Calpine Corporation's
request for Regional Transmission Organizations (RTOs) and
Independent System Operators (ISOs) to be given a deadline to
develop tariff changes that would enable them to implement primary
frequency response compensation mechanisms.
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II. Request for Comments
37. The Commission seeks comment on the need for reforms to its
rules and regulations regarding the provision and compensation of
primary frequency response. Specifically, the Commission seeks comment
on possible actions to ensure that the provision of primary frequency
response continues to remain at levels adequate to maintain the
reliability of the Bulk-Power System in light of the ongoing
transformation of the nation's generation resource mix. The Commission
understands that this transformation in the nation's generation
portfolio could eventually result in a reduction of system inertia and
fewer generation resources with primary frequency response
capabilities. In addition, as discussed above, NERC has indicated that
a significant number of generators within the Eastern Interconnection
utilize dead bands or governor control settings that either inhibit or
prevent the provision of primary frequency response. Together, these
factors could result in potential downward shifts of the frequency
nadir during disturbances, closer to UFLS set points that would trigger
significant widespread outages.
38. Presently, there are no pro forma agreements for primary
frequency response transactions. Voluntary sales of primary frequency
response, would most likely involve negotiated, bilateral contracts
between buyers and sellers. In this regard, considering their
compliance obligations under Reliability Standard BAL-003-1, balancing
authorities will be the most likely source of demand for voluntary
purchases of primary frequency response service from third-party
sellers, including those who have not provided the service in the past.
Accordingly, as discussed further below, the Commission seeks comment
on whether and to what extent balancing authority demand for voluntary
purchases of frequency response would be reduced if all or all newly
interconnecting resources were required to provide frequency response
service. Further, we also seek comment on the impact this would have on
the Commission's efforts under Order No. 819 to foster the development
of a bilateral market for market-based rate sales of primary frequency
response service as a means of cost-effectively meeting such demand.
39. Within RTO/ISO markets, no current stand-alone primary
frequency response product exists. Any RTO/ISO that desires to
explicitly procure and compensate primary frequency response would need
new tariff provisions because no RTO/ISO currently defines or procures
such a product. As discussed below, the Commission seeks comment on the
need for and the nature of frequency response compensation within the
context of current RTO/ISO market optimization processes.
40. Accordingly, the Commission seeks comment on the following
possible actions, discussed in more detail below: (1) Modifications to
the pro forma LGIA and SGIA mandating primary frequency response
requirements for new resources, among other changes; (2) new primary
frequency response requirements for existing resources; and (3) the
requirement to provide and compensate for primary frequency response.
A. Modifications to the pro forma LGIA and SGIA
41. Reliability Standard BAL-003-1 and the pro forma LGIA and SGIA
do not specifically address generators' provision of primary frequency
response. Article 9.6.2.1 of the pro forma LGIA (Governors and
Regulators) requires that if speed governors are installed, they should
be operated in automatic mode.\73\ Reliability Standard BAL-003-1 and
the pro forma LGIA and SGIA do not explicitly: (1) Require generators
to install the necessary capability to provide primary frequency
response; (2) prescribe specific governor settings that would support
the provision of primary frequency response; \74\ or (3) establish
generator primary frequency response performance requirements during
disturbances (e.g., require the response to be sustained, and not
prematurely withdrawn prior to the initiation of secondary frequency
response actions to return system frequency back to its nominal value
and back within a generator's dead band setting).\75\
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\73\ Order No. 2003, FERC Stats. & Regs. ] 31,146, app. C
(LGIA).
\74\ Generator governors can be enabled or disabled which
determines whether or not primary frequency response is provided at
all by the generator. In addition, even if a governor is enabled,
its control settings can limit the conditions under which the
generator provides primary frequency response.
\75\ Primary frequency response would not be expected to be
provided if no capacity (or ``headroom'') is reserved on a unit.
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42. The Commission's pro forma generator interconnection agreements
and procedures were developed at a time when traditional generating
resources with standard governor controls and large rotational inertia
were the predominant sources of electricity generation. However,
circumstances are evolving, with NERC and others predicting significant
[[Page 9189]]
retirements of conventional synchronous resources, all of which
contribute to system inertia, and some of which provide primary
frequency response. In addition, VERs are projected to comprise an
increasing portion of the installed capacity in many regions of the
country, but they do not typically provide inertial response or primary
frequency response unless specifically configured to do so.
43. Regarding VERs, the Commission understands that in previous
years, many non-synchronous resources were not consistently designed
with primary frequency response capabilities. However, NERC and others
have stated that VER manufacturers have made significant advancements
in recent years to develop the necessary controls that would enable
VERs to provide frequency response.\76\ NERC recommends that the
industry analyze how wind and solar photovoltaic resources can
contribute to frequency response and to work toward interconnection
requirements that ensure system operators will continue to maintain
essential reliability services.\77\ Also relevant are PJM's recent
additions of new interconnection requirements for VERs entering its
queue after May 2015.\78\ PJM has stated that the necessary
capabilities for non-synchronous resources to provide primary frequency
response, among other services, are now ``baked in'' as enhancements to
inverter capabilities.\79\
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\76\ NERC Long Term Reliability Assessment at 27 (November
2014), https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2014LTRA_ERATTA.pdf.
\77\ Id.
\78\ PJM Interconnection, L.L.C., 151 FERC ] 61,097, at n.58
(2015).
\79\ PJM Interconnection, L.L.C., Docket No. ER15-1193-000
(March 6, 2015) Transmittal Letter at 11.
---------------------------------------------------------------------------
44. In light of the ongoing changes in the nation's resource mix as
well as NERC's concerns regarding the primary frequency response
performance of existing resources, the Commission seeks comment on
whether and how to modify the pro forma LGIA and SGIA to require
primary frequency response capability and performance of new generating
resources.
45. To that end, the Commission seeks comment on the following
questions:
1. Should the pro forma LGIA and SGIA be revised to include
requirements for all newly interconnecting generating resources,
including non-synchronous resources, to:
1.1. Install the capability necessary to provide primary frequency
response?
1.2. Ensure that prime mover governors (or equivalent frequency
control devices) are enabled and set pursuant to NERC's Primary
Frequency Control Guideline (i.e., droop characteristics not to exceed
5 percent, and dead band settings not to exceed 0.036 Hz)?
1.3. Ensure that the MW response provided (when there is available
headroom) in response to frequency deviations above or below the
governor's dead band from 60 Hz is:
1.3.1. Sustained until system frequency returns to within the
governor's dead band setting?
1.3.2. Provided without undue delay and responds in accordance with
a specified droop parameter?
2. What are the costs associated with making a newly
interconnecting generation resource capable of providing primary
frequency response? Specifically, what are the pieces of equipment or
software needed to provide primary frequency response, and what are the
costs associated with those pieces of equipment or software? Are there
significant differences between synchronous and non-synchronous
resources in providing primary frequency response, (e.g., the type of
equipment necessary)?
3. Regarding question (1) above, are the governor control settings
recommended by NERC's Primary Frequency Control Guideline the
appropriate settings to include in the pro forma LGIA and SGIA? Why or
why not?
4. Regarding new resources, including non-synchronous resources,
are there physical, technical, or operational limitations/concerns to
promptly providing sustained primary frequency response in the
direction necessary to counteract under-frequency and over-frequency
deviations? How should new requirements account for such limitations?
5. Are metrics or monitoring useful to evaluate whether new
resources:
5.1. Operate with governors (or equivalent frequency control
devices) enabled?
5.2. Set governor control settings as described in question (1)
above?
5.3. Provide sustained MW response (when the unit has available
headroom and system frequency deviates outside of the dead band) that
is in the direction necessary to correct the frequency deviation and
responsive in accordance with a specified droop parameter?
6. How would transmission providers verify that new resources
provide adequate primary frequency response performance?
6.1. What information is necessary in order to facilitate
performance verification?
6.2. What changes, if any, to existing infrastructure (including,
but not limited to telemetry and software tools) would be required in
order to verify primary frequency response performance?
6.3. What limitations based on resource type, if any, should be
considered when evaluating primary frequency response performance?
7. How would transmission providers ensure compliance with the new
rules?
7.1. Are penalties appropriate to ensure that new generating
resources adhere to the new requirements described in question (1)
above, and if so, how should such penalties be structured and
implemented?
7.2. Are penalties appropriate only if a resource receives
compensation for adhering to the new requirements described in question
(1) above?
B. New Primary Frequency Response Requirements for Existing Resources
46. The Commission seeks comment on how it might address the issue
of primary frequency response performance in existing generators. As
discussed above, the Commission is considering amendments to the pro
forma LGIA and SGIA that would apply prospectively and only to new
generating resources and not the existing generating fleet. However,
the Commission notes that NERC has also expressed concerns related to
the primary frequency response performance of the existing generating
fleet.
47. For example, in 2010, NERC conducted a governor response survey
to gain insight into governor settings from several turbine governors
across the three U.S. Interconnections.\80\ Analysis revealed a wide
disparity in the reported governor control settings. For example, NERC
found that several generator owners or operators reported dead bands
between 0.05 Hz and 0.3 Hz, which are wider than those prescribed by
ERCOT'S BAL-001-TRE-01 Regional Standard or recommended by NERC's 2015
Generator Governor Frequency Response Industry Advisory \81\ and
Primary Frequency Control Guideline.\82\
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\80\ Frequency Response Initiative Report at 87.
\81\ NERC Generator Governor Frequency Response Industry
Advisory.
\82\ NERC Primary Frequency Control Guideline Final Draft.
---------------------------------------------------------------------------
48. In February 2015, NERC issued an Industry Advisory, which
expressed its determination that a significant portion of generators
within the Eastern Interconnection utilize governor dead bands or other
control settings that
[[Page 9190]]
either inhibit or prevent the provision of primary frequency
response.\83\
---------------------------------------------------------------------------
\83\ NERC Generator Governor Frequency Response Industry
Advisory.
---------------------------------------------------------------------------
49. Furthermore, some generating units have controls that withdraw
primary frequency response prior to the initiation of secondary
frequency controls, which is a significant concern in the Eastern
Interconnection and a somewhat smaller issue in the Western
Interconnection. These controls are known as outer-loop controls to
distinguish them from more direct, lower-level control of the generator
operations. Primary frequency response withdrawal occurs when outer-
loop controls deliberately act to nullify a generator's governor
response and return the unit to operate at a pre-disturbance scheduled
MW output. This is especially problematic when it occurs prior to the
activation of secondary response, and has the potential to degrade the
overall response of the Interconnection and result in a frequency that
declines below the original nadir. NERC has observed that early
withdrawal of primary frequency response continues to occur within the
Eastern Interconnection.\84\
---------------------------------------------------------------------------
\84\ NERC 2015 Frequency Response Annual Analysis Report at vi
(September 2015), https://www.nerc.com/comm/OC/RS%20Landing%20Page%20DL/Related%20Files/2015_FRAA_Report_Final.pdf.
---------------------------------------------------------------------------
50. Furthermore, NERC's Resources Subcommittee has determined that
the majority of gas turbines operate in some type of MW Set Point
control mode.\85\ According to the NERC Resources Subcommittee, the
Eastern Interconnection Initiative has uncovered that in order for gas
turbines to respond in MW Set Point control mode, an additional
frequency algorithm has to be installed.\86\ Moreover, NERC's Resources
Subcommittee stated that ``the net result is that the gas turbine fleet
that has been installed in the past 20+ years is not frequency
responsive, [which] has to be corrected.'' \87\ NERC has also observed
that in many conventional steam plants, dead band settings exceed the
maximum 0.036 Hz dead band, and the resulting response is
squelched and not sustained.\88\
---------------------------------------------------------------------------
\85\ See News from SERC's NERC Resources Subcommittee Rep--
Primary Frequency Response at 1 (May 2015), https://www.serc1.org/
docs/default-source/outreach/communications/resource-documents/serc-
transmission-reference/201505_-st/primary-frequency-
response.pdf?sfvrsn=2. MW set-point control mode automatically
interrupts governor response in order for a generating unit to
maintain a pre-disturbance dispatch.
\86\ Id.
\87\ Id.
\88\ See NERC Generator Governor Frequency Response Advisory--
Webinar Questions and Answers at 1 (April 2015), https://www.nerc.com/pa/rrm/Webinars%20DL/Generator_Governor_Frequency_Response_Webinar_QandA_April_2015.pdf.
---------------------------------------------------------------------------
51. As noted above, in December 2015, NERC's Operating Committee
approved a 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 during major grid events in order to stabilize and maintain
system frequency within allowable limits.\89\ However, the Commission
notes that NERC's Primary Frequency Control Guideline is not mandatory
and enforceable and does not alter any approved Reliability Standards.
---------------------------------------------------------------------------
\89\ NERC Primary Frequency Control Guideline Final Draft.
---------------------------------------------------------------------------
52. In light of the above discussion, the Commission seeks to
further explore issues regarding the provision of primary frequency
response by the existing generation fleet and seeks comment on the
following questions:
1. Should the Commission implement primary frequency response
requirements for existing resources, as discussed above for new
generators? If so, what is an appropriate means of doing so (e.g.,
changes to transmission provider tariffs or improvements to existing
reliability standards)? How would transmission providers ensure that
existing resources adhere to new primary frequency response
requirements?
2. As noted above, some existing generating units set dead bands
wider than those recommended by NERC's Primary Frequency Control
Guideline, and some units have control settings set in a manner that
results in the premature withdrawal of primary frequency response.
Should the Commission prohibit these practices? If so, by what means?
3. What are the costs of retrofitting existing units, including
non-synchronous resources, and with specific reference to such factors
as equipment types and MW capacity, to be capable of providing
sustained primary frequency response?
4. Regarding existing units, are there physical, technical, or
operational limitations or concerns to promptly providing sustained
primary frequency response in the direction necessary to counteract
under-frequency and over-frequency deviations?
C. Requirement to Provide and Compensate for Primary Frequency Response
Service
53. Without the explicit requirement to provide primary frequency
response or appropriate compensation for the provision of such service,
resource owners may choose to disable or otherwise reduce the provision
of primary frequency response from their existing resources or not
install the equipment on their new resources.\90\
---------------------------------------------------------------------------
\90\ IEEE, Interconnected Power System Response to Generation
Governing: Present Practice and Outstanding Concerns (May 2007)
(citing Cost of Providing Ancillary Services from Power Plants--
Volume 1: A Primer, EPRI TR-1 07270-V1, 4161, Final Report, March
1997), https://resourcecenter.ieee-pes.org/pes/product/technical-reports/PESTR13.
---------------------------------------------------------------------------
54. The Commission seeks information on whether there is a need to
establish or modify procurement and compensation mechanisms for primary
frequency response, and whether these mechanisms will ensure that the
resulting rates are just and reasonable. The Commission invites
commenters to share their overall views, including the operational,
technical and commercial impacts that may result from mandates to
provide primary frequency response. To that end, the Commission seeks
comment on the following questions:
1. Should all resources be required to provide minimum levels of:
(1) Primary frequency response capability; and (2) primary frequency
response performance in real-time?
1.1. ``Capability'' involves having a turbine governor or
equivalent equipment that has the ability to sense changes in system
frequency, and is enabled and set with appropriate governor settings
(e.g., droop and dead band), and assuming capacity (or ``headroom'')
has been set aside, the physical ability to ramp the resource quickly
enough in order to provide useful levels of primary frequency response
to help arrest the frequency deviation.
1.2. ``Performance'' would involve putting the ``capability'' into
actual service: i.e., actually operating the resource with governors or
equivalent equipment enabled, ensuring that governor controls (e.g.,
droop and dead band) and other settings are properly set and
coordinated, such that when capacity (or ``headroom'') has been set
aside, the unit promptly provides sustained primary frequency response
during frequency excursions, until system frequency returns to within
the governor's dead band setting.
2. Is it necessary for every generating resource to install the
capability necessary to provide primary frequency
[[Page 9191]]
response? Or is it more appropriate for balancing authorities to
identify and procure the amount of primary frequency response service
that they need to meet their obligations under Reliability Standard
BAL-003-1 and the optimum mix of resources to meet that need?
2.1. To the extent that balancing authorities are responsible for
procuring adequate primary frequency response service, does the current
framework for blackstart provide a useful guide for how primary
frequency response service could be procured?
2.2. Does the Commission's recent rulemaking allowing third-party
sales of frequency response services at market based rates allow
balancing authorities to procure sufficient amounts of primary
frequency response as required by BAL-003-1?
2.3. To the extent that balancing authorities centrally optimize
primary frequency response, wherein an algorithm optimizes in the
operating horizon the set of resources in which to allocate primary
frequency response headroom: Should all newly interconnecting resources
be required to install the necessary capability in these areas? Can
balancing authorities predict far ahead of the operating horizon the
least-cost set of resources from which it will optimize the provision
of primary frequency response?
2.4. Would the costs of requiring all resources to have the
capability to provide primary frequency response be significantly
greater than the costs that would result from an Interconnection-wide
or balancing authority-wide optimization of which generators should be
capable of providing primary frequency response?
2.5. Would the costs of requiring all new resources to enable and
set their governors, or equivalent equipment, to be able to provide
primary frequency response in real-time be significantly greater than
the costs that would result from an Interconnection-wide or balancing
authority-wide optimization of which generators should provide primary
frequency response in real-time?
2.6. Please discuss the viability of implementing an
Interconnection-wide optimization mechanism.
2.7. Would requiring every resource to be capable of providing
primary frequency response result in over-procurement or inefficient
investment in primary frequency response capability to the detriment of
customers?
2.8. Without rules to compel performance, how would balancing
authorities ensure that the optimal set of resources chosen by an
optimization algorithm actually enable governor controls with
appropriate governor settings so that they provide sustained primary
frequency response when capacity (or ``headroom'') has been reserved
and frequency deviates outside of their dead band settings?
3. If generation resources were required to have minimum levels of
primary frequency response capability or performance, should such
resources be compensated for providing primary frequency response
capability, performance, or both? If so, why? If not, why?
3.1. If payment is based on capacity (or ``headroom'') that is set
aside for primary frequency response, how should such a capacity
payment be structured and determined?
3.2. If payment is based on actual performance, either alone or in
combination with a capacity-based payment, please discuss possible rate
structures applicable to primary frequency response performance.
3.3. Will a market price provide resources with sufficient
incentive to invest in primary frequency response capability and make
the service available to the balancing authority in real-time, absent a
requirement that resources maintain the capability to provide primary
frequency response and perform as required?
4. Currently, how do RTOs/ISOs ensure that they have the
appropriate amount of primary frequency response capability during
operations?
4.1. Are resources contracted for primary frequency response
outside of the market optimization and dispatch?
4.2. Alternatively, does the market optimization and dispatch
incorporate primary frequency response in its optimization?
5. Would it be appropriate for RTOs/ISOs to create a product for
primary frequency response service?
5.1. Should this product be similar to a capacity product for the
procurement of primary frequency response capability from resources?
5.2. Should this product be similar to other ancillary service
products in which certain resources would be selected in the day-ahead
or real-time markets to provide primary frequency response?
5.3. Are there benefits to co-optimizing the capacity (or
``headroom'') allocated on generating units for primary frequency
response with the market optimization and dispatch of RTOs/ISOs? If so,
what are the challenges associated with doing so?
6. Are there benefits to separating Frequency Response Service
under Schedule 3 and creating a separate ancillary service covering
each individually? If so, how should a new pro forma Primary Frequency
Response Ancillary Service be structured?
7. When compensating for primary frequency response, should
compensation be different inside and outside of RTOs/ISOs?
8. What procurement requirements or compensation mechanisms could
be used for primary frequency response from stored energy resources?
When considering requirements or compensation for stored energy
resources, how should possible additional costs or other concerns be
addressed?
III. Comment Procedures
55. The Commission invites interested persons to submit comments,
and other information on the matters, issues and specific questions
identified in this notice. Comments are due April 25, 2016. 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.
56. 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.
57. 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.
58. 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.
IV. Document Availability
59. 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 FERC's Home Page (https://www.ferc.gov) and in FERC's
Public Reference Room during normal business hours (8:30 a.m. to 5:00
p.m. Eastern
[[Page 9192]]
time) at 888 First Street NE., Room 2A, Washington, DC 20426.
60. From FERC'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.
61. User assistance is available for eLibrary and the FERC's Web
site during normal business hours from FERC 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: February 18, 2016.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2016-03837 Filed 2-23-16; 8:45 am]
BILLING CODE 6717-01-P
