[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]
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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.
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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,
http://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 http://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, [email protected].
Mark Bennett (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street NE., Washington,
DC 20426, (202) 502-8524, [email protected].
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.
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\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).
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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\
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\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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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.
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\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: http://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.
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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), http://www.seia.org/research-resources/solar-market-insight-report-2015-q1.
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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\
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\13\ See NERC 2015 Long Term Reliability Assessment at 1
(December 2015), http://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), http://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), http://site.ge-energy.com/prod_serv/products/renewable_energy/en/downloads/GEA17210.pdf.
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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.
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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\
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\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), http://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/Scope_ERSTF_Final.pdf.
\22\ Essential Reliability Services Task Force Measures Report
at 22 (December 2015), http://www.nerc.com/comm/Other/essntlrlbltysrvcstskfrcDL/ERSTF%20Framework%20Report%20-%20Final.pdf.
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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\
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\28\ Essential Reliability Services Task Force Measures Report
at iv.
\29\ See NERC State of Reliability 2015 Report at 16 (May 2015),
http://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%20DL/2015%20State%20of%20Reliability.pdf.
\30\ Essential Reliability Services Task Force Measures Report
at vi.
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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.
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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), http://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), http://www.nerc.com/comm/OC/Reliability%20Guideline%20DL/Primary_Frequency_Control_final.pdf.
See also NERC Operating Committee Meeting Minutes (January 2016),
http://www.nerc.com/comm/OC/AgendasHighlightsMinutes/Operating%20Committee%20Minutes%20-%20Dec%2015-16%202015-Final.pdf.
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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
http://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),
http://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), http://energy.lbl.gov/ea/certs/pdf/lbnl-4144e.pdf.
\36\ See NERC Frequency Response Initiative Report: The
Reliability Role of Frequency Response (October 2012), http://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.
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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.
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\43\ Reactive Power Requirements for Non-Synchronous Generation,
153 FERC ] 61,175 (2015).
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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.
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\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).
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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.
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\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), http://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.
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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), http://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, http://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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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), http://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\
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\84\ NERC 2015 Frequency Response Annual Analysis Report at vi
(September 2015), http://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), http://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), http://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 http://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 (http://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
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at
[email protected].
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