81_FR_9218 81 FR 9182 - Essential Reliability Services and the Evolving Bulk-Power System-Primary Frequency Response

81 FR 9182 - Essential Reliability Services and the Evolving Bulk-Power System-Primary Frequency Response

DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission

Federal Register Volume 81, Issue 36 (February 24, 2016)

Page Range9182-9192
FR Document2016-03837

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.

Federal Register, Volume 81 Issue 36 (Wednesday, February 24, 2016) 
[Federal Register Volume 81, Number 36 (Wednesday, February 24, 2016)]
[Notices]
[Pages 9182-9192]
From the Federal Register Online  [www.thefederalregister.org]
[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, 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.
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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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    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), 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\
---------------------------------------------------------------------------

    \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 
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

9182 Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices DEPARTMENT OF ENERGY Commission’s Public Reference Room in Jomo Richardson (Technical Washington, DC. There is an Information), Office of Electric Federal Energy Regulatory eSubscription link on the Web site that Reliability, Federal Energy Regulatory Commission enables subscribers to receive email Commission, 888 First Street NE., [Docket No. EL16–39–000] notification when a document is added Washington, DC 20426, (202) 502– to a subscribed docket(s). For assistance 6281, Jomo.Richardson@ferc.gov. Tri-State Generation and Transmission with any FERC Online service, please Mark Bennett (Legal Information), Office Association, Inc.; Notice of Petition for email FERCOnlineSupport@ferc.gov.or of the General Counsel, Federal Declaratory Order call (866) 208–3676 (toll free). For TTY, Energy Regulatory Commission, 888 call (202) 502–8659. Take notice that on February 17, 2016, Comment Date: 5:00 p.m. Eastern time First Street NE., Washington, DC pursuant to Rule 207 of the on March 18, 2016. 20426, (202) 502–8524, Commission’s Rules of Practice and Mark.Bennett@ferc.gov. Procedure of the Federal Energy Dated: February 18, 2016. Nathaniel J. Davis, Sr., SUPPLEMENTARY INFORMATION: Regulatory Commission’s (Commission), 18 CFR 385.207(2015), Tri-State Deputy Secretary. 1. In this Notice of Inquiry (NOI), the Generation and Transmission [FR Doc. 2016–03835 Filed 2–23–16; 8:45 am] Commission seeks comment on the need Association, Inc. (Tri-State) filed a BILLING CODE 6717–01–P for reforms to its rules and regulations petition for declaratory order finding regarding the provision and that Tri-State’s fixed cost recovery compensation of primary frequency proposal contained in revised Board DEPARTMENT OF ENERGY response. In recent years, the nation’s Policy 101 is consistent with the Public electric supply portfolio has Utility Regulatory Policies Act of 1978 Federal Energy Regulatory transformed to a point where fewer and the Commission’s implementing Commission resources may now be providing regulaltions, as more fully explained in [Docket No. RM16–6–000] primary frequency response than when the petition. the Commission considered this issue in Any person desiring to intervene or to Essential Reliability Services and the other relevant proceedings. As protest in this proceeding must file in Evolving Bulk-Power System—Primary discussed below, in light of the accordance with Rules 211 and 214 of Frequency Response changing resource mix and other factors, the Commission’s Rules of Practice and it is reasonable to expect this trend to AGENCY: Federal Energy Regulatory Procedure (18 CFR 385.211 and Commission, Energy. continue. Considering the significance 385.214) on or before 5:00 p.m. Eastern ACTION: Notice of Inquiry. of primary frequency response to the time on the specified comment date. reliable operation of the Bulk-Power Protests will be considered by the SUMMARY: In this Notice of Inquiry, the System,1 the Commission seeks input Commission in determining the Federal Energy Regulatory Commission appropriate action to be taken, but will on whether and what action is needed (Commission) seeks comment on the to address the provision and not serve to make protestants parties to need for reforms to its rules and the proceeding. Any person wishing to compensation of primary frequency regulations regarding the provision and response. become a party must file a notice of compensation of primary frequency intervention or motion to intervene, as response. 2. Specifically, the Commission seeks appropriate. Such notices, motions, or comment on whether amendments to DATES: Comments are due April 25, protests must be filed on or before the the pro forma Large Generator comment date. Anyone filing a motion 2016. Interconnection Agreement (LGIA) and to intervene or protest must serve a copy ADDRESSES: You may submit comments, Small Generator Interconnection of that document on the Petitioner. identified by docket number and in Agreement (SGIA) are warranted to The Commission encourages accordance with the requirements require all new generation resources to electronic submission of protests and posted on the Commission’s Web site, have frequency response capabilities as interventions in lieu of paper, using the http://www.ferc.gov. Comments may be a precondition of interconnection. The FERC Online links at http:// submitted by any of the following Commission also seeks comment on the www.ferc.gov. To facilitate electronic methods: performance of existing resources and service, persons with Internet access • Agency Web site: Documents whether primary frequency response who will eFile a document and/or be created electronically using word requirements for these resources are listed as a contact for an intervenor processing software should be filed in warranted. Further, the Commission must create and validate an native applications or print-to-PDF seeks comment on the requirement to eRegistration account using the format and not in a scanned format, at provide and compensate for primary eRegistration link. Select the eFiling http://www.ferc.gov/docs-filing/ frequency response. link to log on and submit the efiling.asp. intervention or protests. • Mail/Hand Delivery: Those unable 1 Section 215(a)(1) of the Federal Power Act Persons unable to file electronically to file electronically must mail or hand (FPA), 16 U.S.C. 824o(a)(1) (2012) defines ‘‘Bulk- should submit an original and 5 copies deliver comments to: Federal Energy Power System’’ as those ‘‘facilities and control of the intervention or protest to the Regulatory Commission, Secretary of the systems necessary for operating an interconnected electric energy transmission network (or any mstockstill on DSK4VPTVN1PROD with NOTICES Federal Energy Regulatory Commission, Commission, 888 First Street NE., portion thereof) [and] electric energy from 888 First Street NE., Washington, DC Washington, DC 20426. generating facilities needed to maintain 20426. Instructions: For detailed instructions transmission system reliability.’’ The term does not The filings in the above proceeding on submitting comments and additional include facilities used in the local distribution of are accessible in the Commission’s information on the rulemaking process, electric energy. See also Mandatory Reliability see the Comment Procedures Section of Standards for the Bulk-Power System, Order No. eLibrary system by clicking on the 693, FERC Stats. & Regs. ¶ 31,242, at P 76, order appropriate link in the above list. They this document. on reh’g, Order No. 693–A, 120 FERC ¶ 61,053 are also available for review in the FOR FURTHER INFORMATION CONTACT: (2007). VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 PO 00000 Frm 00022 Fmt 4703 Sfmt 4703 E:\FR\FM\24FEN1.SGM 24FEN1

Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices 9183 I. Background 5. Inertial response, or system inertia, resources on automatic generation involves the release or absorption of control (e.g., regulation resources) that A. Technical Overview: The Nature and kinetic energy by the rotating masses of respond to dispatch instructions.10 Operation of Frequency Response online generation and load within an Secondary frequency response actions 3. Reliably operating an Interconnection, and is the result of the usually begin after 30 seconds or more Interconnection 2 requires maintaining coupling between the rotating masses of following a contingency, and can take 5 balance between generation and load so synchronous generation and load and minutes or more to restore system that frequency remains within the electric system.6 An frequency to its scheduled value. predetermined boundaries around a Interconnection’s inertial response scheduled value (60 Hz in the United B. Evolving Generation Resource Mix influences how fast frequency drops States). Interconnections occasionally after the loss of generation and how fast 8. The nation’s generation resource experience system contingencies (e.g., it rises after a reduction of load. The less mix is undergoing a transformation that the loss of a large generator) that disrupt system inertia there is, the faster the rate includes the retirement of baseload, the balance between generation and of change of frequency 7 during synchronous units, with large rotational load. These contingencies result in disturbances. An adequate amount of inertia. The changing resource mix also frequency deviations that can system inertia is important since includes the integration of more potentially cause under frequency load following the sudden loss of generation, distributed generation, demand shedding (UFLS), additional generation inertia serves to reduce the rate of response, and natural gas resources, and tripping, or cascading outages.3 change of frequency, allowing time for the rapid expansion of variable energy Consequently, some generators within primary frequency response actions to resources (VERs) 11 such as wind and an Interconnection automatically deploy arrest the frequency deviation and solar.12 Several factors, such as existing frequency control actions, including stabilize the power system. and proposed federal and state inertial response and primary frequency 6. Primary frequency response, net of environmental regulations, renewable response, during disturbances to arrest changes in generation real power (MW) portfolio standards, tax incentives, and and stabilize frequency deviations. The output and power consumed by load in low natural gas prices, have driven reliability of the Bulk-Power System response to a frequency deviation, is the these developments. depends in part on the operating first stage of overall frequency control, 9. During 2015, natural gas-fired characteristics of generating resources begins within seconds after the generation surpassed coal as the that balancing authorities 4 commit to frequency changes, and is critical to the predominant fuel source for electric serve load. However, not all generating reliable operation of the Bulk-Power generation, and is now the leading fuel resources provide frequency support System.8 Primary frequency response is type for capacity additions.13 In services, which are essential to mostly provided by the automatic and addition, NERC recently determined maintaining the reliability and stability autonomous actions (i.e., outside of that there has been almost 50 GW of of the Bulk-Power System.5 system operator control) of turbine- baseload (e.g., coal, nuclear, petroleum, 4. Frequency response is a measure of governors, while some response is and natural gas) retirements since an Interconnection’s ability to arrest and provided by frequency responsive loads 2011.14 stabilize frequency deviations within due to changes in system frequency. 10. In addition, between 2014 and pre-determined limits following the Primary frequency response actions are 2015, all three U.S. Interconnections sudden loss of generation or load. intended to arrest the frequency have experienced growth in the Frequency response is affected by the deviation until it reaches the minimum installed nameplate capacity of wind collective responses of generation and frequency, or nadir.9 An important goal and solar generation. For example, as load resources throughout the entire for system planners and operators is for illustrated by the figure below, NERC Interconnection. Inertial response, the frequency nadir, during large primary frequency response, and disturbances, to remain above the first 10 See e.g., LBNL Frequency Response Metrics secondary frequency response all Report at 9–11. stage of firm UFLS set points within an 11 For the purposes of this proceeding, the term contribute to stabilizing the Bulk-Power Interconnection. The time-frame to Variable Energy Resource refers to a device for the System by correcting frequency arrest frequency deviations typically production of electricity that is characterized by an deviations. ranges from five to 15 seconds, energy source that: (1) Is renewable; (2) cannot be stored by the facility owner or operator; and (3) has depending on the Interconnection. variability that is beyond the control of the facility 2 An Interconnection is a geographic area in 7. Secondary frequency response owner or operator. This includes, for example, which the operation of Bulk-Power System components is synchronized. In the continental involves changes to the MW output of wind, solar thermal and photovoltaic, and United States, there are three Interconnections, hydrokinetic generating facilities. See Integration of namely the Eastern, Electric Reliability Council of 6 See, e.g., Use of Frequency Response Metrics to Variable Energy Resources, Order No. 764, FERC Texas (ERCOT), and Western Interconnections. Assess the Planning and Operating Requirements Stats. & Regs. ¶ 31,331 at n. 1 (2012), order on reh’g 3 UFLS is designed for use in extreme conditions for Reliable Integration of Variable Renewable and clarification, Order No. 764–A, 141 FERC ¶ to stabilize the balance between generation and Generation, Ernest Orlando Lawrence Berkeley 61,232 (2012), order on clarification and reh’g, load. Under frequency protection schemes are National Laboratory, at 13–14 (December 2010), Order No. 764–B, 144 FERC ¶ 61,222 (2013). 12 The Solar Energy Industries Association (SEIA) drastic measures employed if system frequency falls available at: http://energy.lbl.gov/ea/certs/pdf/lbnl- below a specified value. Automatic Underfrequency 4142e.pdf (LBNL Frequency Response Metrics recently reported that more than 50 percent of Load Shedding and Load Shedding Plans Reliability Report). newly installed electric generating capacity in the Standards, Notice of Proposed Rulemaking, 137 7 Rate of change of frequency is mainly a function U.S. came from solar generation in the first quarter FERC ¶ 61,067 (2011). of the magnitude of the loss of generation (or load) of 2015. See SEIA Solar Market Insight Report 2015 4 The North American Electric Reliability and system inertia and is measured in Hz/second. Q1 (2015), http://www.seia.org/research-resources/ solar-market-insight-report-2015-q1. mstockstill on DSK4VPTVN1PROD with NOTICES Corporation’s (NERC) Glossary of Terms defines a 8 See, e.g., LBNL Frequency Response Metrics 13 See NERC 2015 Long Term Reliability balancing authority as ‘‘(t)he responsible entity that Report at 15–16. integrates resource plans ahead of time, maintains 9 The point at which the frequency decline is Assessment at 1 (December 2015), http:// load-interchange-generation balance within a arrested (following the sudden loss of generation) www.nerc.com/pa/RAPA/ra/ balancing authority area, and supports is called the frequency nadir, and represents the Reliability%20Assessments%20DL/2015LTRA%20- Interconnection frequency in real time.’’ point in which the net primary frequency response %20Final%20Report.pdf. 5 As discussed below, NERC Reliability Standard 14 See NERC 2015 Summer Reliability (MW) output from all generating units and the BAL–003–1 has requirements related to frequency decrease in power consumed by the load within an Assessment at 5 (May 2015), http://www.nerc.com/ response, but it is applicable to balancing Interconnection matches the net initial MW loss of pa/RAPA/ra/Reliability%20Assessments%20DL/ authorities and not individual generating resources. generation. 2015_Summer_Reliability_Assessment.pdf. VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 PO 00000 Frm 00023 Fmt 4703 Sfmt 4703 E:\FR\FM\24FEN1.SGM 24FEN1

9184 Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices has observed that the three solar capacity, representing a growth levels of 11.4 GW and 0.12 GW;17 and Interconnections collectively added rate of 12 percent and 116 percent over (3) Western Interconnection had 24.8 approximately 11.1 GW of wind and the respective 2014 levels of 33.5 GW GW of wind and 8.4 GW of solar, 1.73 GW of solar generation between and 0.73 GW;16 (2) ERCOT had 14.7 GW representing a growth rate of 17 percent 2014 and 2015.15 More specifically, in of wind and 0.18 GW of solar, and 11 percent over the respective 2014 2015: (1) The Eastern Interconnection representing a growth rate of 29 percent levels of 21.1 GW and 7.6 GW.18 had 37.6 GW of wind and 1.6 GW of and 50 percent over the respective 2014 11. The changing generation resource 12. In addition, VERs do not provide responsive capability online may mix has the potential to reduce the primary frequency response unless adversely affect reliability during inertial response within some specifically configured to do so. disturbances because lower system Interconnections, as VERs do not Furthermore, since VERs typically have inertia results in more rapid frequency contribute to inertia unless they are low marginal costs of production, they deviations during disturbances. This, in specifically designed to do so. For would likely not be dispatched in a turn, may result in lower frequency example, solar photovoltaic resources manner necessary to provide primary nadirs, particularly if the primary have no rotating mass and thus no frequency response, since the provision frequency capability online is not rotational inertia. Similarly, while wind of primary frequency response involves sufficiently fast. This is a potential turbines have a rotating mass, power the reservation of capacity (or reliability concern because, as the converters that interconnect modern ‘‘headroom’’) in order for a resource to frequency nadir lowers, it approaches wind turbines decouple the rotation of automatically increase its MW output in the Interconnection’s UFLS trip setting, response to drops in system frequency. which could result in the loss of load their turbines from the grid. As such, Therefore, there is a significant risk that, and additional generation across the modern wind turbines do not contribute as conventional synchronous resources Interconnection. to the system’s inertia unless retire or are displaced by increased specifically configured to do so.19 14. These developments and their numbers of VERs that do not typically potential impacts could challenge Therefore, increased numbers of VERs, have primary frequency response in conjunction with significant system operators in maintaining capabilities, the net amount of reliability. The Commission believes retirements of large conventional frequency responsive generation online that a substantial body of evidence has resources with large rotational inertia, will be reduced.20 emerged warranting consideration of have the potential to reduce system 13. The combined impacts of lower possible actions to ensure that resources inertia. mstockstill on DSK4VPTVN1PROD with NOTICES system inertia and lower frequency capable of providing primary frequency 15 NERC 2015 Summer Reliability Assessment, prod_serv/products/renewable_energy/en/ Inverters convert non-synchronized AC or DC Table 3 at page 7. downloads/GEA17210.pdf. power into synchronized AC power that can be 16 Id. 20 Non-synchronous generators such as VERs transmitted on the transmission system. These 17 Id. (e.g., wind and solar resources) produce electricity resources do not operate in the same way as 18 Id. that is not synchronized to the electric grid (i.e., conventional generators and respond differently to 19 See, e.g., General Electric WindINERTIA direct current (DC) power or alternating current network disturbances. EN24FE16.030</GPH> Control Fact Sheet (2009), http://site.ge-energy.com/ (AC) power at a frequency other than 60 hertz). VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 PO 00000 Frm 00024 Fmt 4703 Sfmt 4703 E:\FR\FM\24FEN1.SGM 24FEN1

Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices 9185 response are adequately maintained as that essential reliability services Advisory which determined that a the nation’s resource mix continues to continue to be provided as the nation’s significant portion of generators within evolve. generation resource mix evolves.27 the Eastern Interconnection utilize dead 15. In 2014, NERC initiated the 17. The reliability of the Bulk-Power bands or governor control settings that Essential Reliability Services Task Force System will be increasingly dependent either inhibit or prevent the provision of (Task Force) to analyze and better upon the operational characteristics of primary frequency response.32 In understand the impacts of the changing natural gas and renewable generating response to this issue and other resource mix and develop technical units, as these types of resources are concerns, NERC’s Operating Committee assessments of essential reliability expected to comprise an increasing recently approved a Primary Frequency services.21 The Task Force focused on percentage of the future generation Control Guideline that contains three essential reliability services: resource mix. The Task Force stated that recommended settings for generator frequency support, ramping capability, ‘‘the reliability of the electric grid governors and other plant control and voltage support.22 depends on the operating characteristics systems, and encourages generators 16. The Task Force considered the of the replacement resources.’’ 28 NERC within the three U.S. Interconnections seven ancillary services 23 adopted by observed that ‘‘wind, solar, and other to provide sustained and effective the Commission in Order Nos. 888 24 variable energy resources that are an primary frequency response.33 and 890 25 as a subset of the essential increasingly greater share of the Bulk- 20. NERC’s State of Reliability Report reliability services that may need to be Power System provide a significantly for 2015 explained that the three U.S. augmented by additional services as the lower level of essential reliability Interconnections currently exhibit stable Bulk-Power System characteristics services than conventional frequency response performance above change. However, the Task Force did generation.’’ 29 The Task Force their Interconnection Frequency not intend to recommend new reliability concluded that it is prudent and Response Obligations.34 However, standards or propose actions to alter the necessary to ensure that primary NERC has pointed out a historic decline existing suite of ancillary services.26 frequency capabilities are present in the in frequency response performance in Instead, its focus was on educating and future generation resource mix, and both the Western and Eastern informing industry and other recommends that all new generators Interconnections.35 NERC identified stakeholders about essential reliability support the capability to manage several key reasons for the decline, services, developing measures and frequency.30 mainly tied to the primary frequency industry best practices for tracking 18. Contributing to the concerns response performance of generators.36 essential reliability services, and associated with the nature and developing recommendations to ensure operational characteristics of the C. Prior Commission and Industry evolving resource mix is the uncertainty Actions 21 Essential reliability services are referred to as whether a resource configured to 21. In this proceeding, the elemental reliability building blocks from resources provide primary frequency response is (generation and load) that are necessary to maintain Commission seeks comment on the need the reliability of the Bulk-Power System. See willing and able to offer such a service Essential Reliability Services Task Force Scope when called upon to do so. While 32 NERC Generator Governor Frequency Response Document at 1 (April 2014), http://www.nerc.com/ almost all existing synchronous Industry Advisory (February 2015), http:// comm/Other/essntlrlbltysrvcstskfrcDL/Scope_ resources and some non-synchronous www.nerc.com/pa/rrm/bpsa/Alerts%20DL/ ERSTF_Final.pdf. 2015%20Alerts/NERC%20Alert%20A-2015-02-05- 22 Essential Reliability Services Task Force resources have governors or equivalent 01%20Generator%20Governor%20Frequency%20 Measures Report at 22 (December 2015), http:// control equipment capable of providing Response.pdf. www.nerc.com/comm/Other/ primary frequency response, generator 33 See NERC Primary Frequency Control essntlrlbltysrvcstskfrcDL/ owners and operators can Guideline Final Draft (December 2015), http:// ERSTF%20Framework%20Report%20- independently decide whether units www.nerc.com/comm/OC/ %20Final.pdf. Reliability%20Guideline%20DL/Primary_ 23 The seven ancillary services are: (1) provide primary frequency response.31 Frequency_Control_final.pdf. See also NERC Scheduling, System Control and Dispatch Service; 19. For example, at present, it is Operating Committee Meeting Minutes (January (2) Reactive Supply and Voltage Control from possible for a generator owner/operator 2016), http://www.nerc.com/comm/OC/Agendas Generation Sources Service; (3) Regulation and to block or disable the governor or to set HighlightsMinutes/Operating%20 Frequency Response Service; (4) Energy Imbalance a wide dead band setting. A wide dead Committee%20Minutes%20-%20Dec%2015-16 Service; (5) Operating Reserve—Spinning Reserve %202015-Final.pdf. Service; (6) Operating Reserve—Supplemental band setting can result in a unit not 34 NERC State of Reliability Report 2015 at 9 (May Reserve Service; and (7) Generator Imbalance providing primary frequency response 2015). See http://www.nerc.com/pa/RAPA/PA/ Service. for most frequency deviations. As Performance%20Analysis%20DL/2015%20State 24 Promoting Wholesale Competition Through discussed more fully below, in February %20of%20Reliability.pdf. Reliability Standard Open Access Non-Discriminatory Transmission 2015, NERC issued an Industry BAL–003–1 establishes Interconnection Frequency Services by Public Utilities; Recovery of Stranded Response Obligations that are designed to require Costs by Public Utilities and Transmitting Utilities, sufficient frequency response for each 27 Id. Order No. 888, FERC Stats. & Regs. ¶ 31,036 (1996), Interconnection to arrest frequency declines even 28 Essential Reliability Services Task Force order on reh’g, Order No. 888–A, FERC Stats. & for severe, but possible, contingencies. Regs. ¶ 31,048, order on reh’g, Order No. 888–B, 81 Measures Report at iv. 35 See NERC Frequency Response Initiative FERC ¶ 61,248 (1997), order on reh’g, Order No. 29 See NERC State of Reliability 2015 Report at 16 Industry Advisory—Generator Governor Frequency 888–C, 82 FERC ¶ 61,046 (1998), aff’d in relevant (May 2015), http://www.nerc.com/pa/RAPA/PA/ Response at slide 10 (April 2015), http:// part sub nom. Transmission Access Policy Study Performance%20Analysis%20DL/ www.nerc.com/pa/rrm/Webinars%20DL/Generator_ Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d 2015%20State%20of%20Reliability.pdf. Governor_Frequency_Response_Webinar_April_ sub nom. New York v. FERC, 535 U.S. 1 (2002). 30 Essential Reliability Services Task Force 2015.pdf. See also Review of the Recent Frequency 25 Preventing Undue Discrimination and Measures Report at vi. Performance of the Eastern, Western and ERCOT mstockstill on DSK4VPTVN1PROD with NOTICES Preference in Transmission Service, Order No. 890, 31 A governor is an electronic or mechanical Interconnections, Ernest Orlando Lawrence FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order device that implements primary frequency response Berkeley National Laboratory, at pp xiv–xv No. 890–A, FERC Stats. & Regs. ¶ 31,261 (2007), on a generator via a droop parameter. Droop refers (December 2010), http://energy.lbl.gov/ea/certs/pdf/ order on reh’g, Order No. 890–B, 123 FERC ¶ 61,299 to the variation in MW output due to variations in lbnl-4144e.pdf. (2008), order on reh’g, Order No. 890–C, 126 FERC system frequency. A governor also has a dead band 36 See NERC Frequency Response Initiative ¶ 61,228, order on clarification, Order No. 890–D, which establishes a minimum frequency deviation Report: The Reliability Role of Frequency Response 129 FERC ¶ 61,126 (2009). (from nominal) that must be exceeded in order for (October 2012), http://www.nerc.com/docs/pc/FRI_ 26 NERC Essential Reliability Services Task Force the governor to act. Example droop and dead band Report_10-30-12_Master_w-appendices.pdf Scope Document at 2. settings are 5 percent and ±0.036 Hz, respectively. (Frequency Response Initiative Report). VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 PO 00000 Frm 00025 Fmt 4703 Sfmt 4703 E:\FR\FM\24FEN1.SGM 24FEN1

9186 Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices for reforms to its rules and regulations terms and conditions for new share of the Interconnection Frequency regarding the provision of primary interconnecting small generators (i.e., Response Obligation, and is based on its frequency response. This section offers those no larger than 20 MW) under a pro annual generation and load.47 an overview of Commission and forma SGIA.42 Requirement R1 of BAL–003–1 requires industry action to date related to 25. The Commission recently issued a each balancing authority to achieve an frequency response to provide the notice of proposed rulemaking to revise annual Frequency Response Measure context for the consideration of what, if the pro forma LGIA and SGIA to that equals or exceeds its Frequency any, actions the Commission should eliminate the exemption for wind Response Obligation. The Frequency take to ensure that adequate frequency generators and other non-synchronous Response Measure is the median value response is available to maintain grid generators regarding reactive power of a balancing authority’s frequency reliability. requirements.43 The proposed rule response performance during selected 22. In April 1996, the Commission proposes to require all newly events over the course of a year.48 issued Order No. 888, to address undue interconnecting generators, both Requirement R1 of BAL–003–1 becomes discrimination in transmission service synchronous and non-synchronous, to effective on April 1, 2016, and by requiring all public utilities to provide reactive power. compliance begins on December 1, provide open access transmission 26. Although the Commission has 2016. service consistent with the terms of a previously included technical 28. Although Reliability Standard pro forma Open Access Transmission requirements for generators in the LGIA BAL–003–1 requires sufficient Tariff (OATT).37 The pro forma OATT and Large Generator Interconnection frequency response from balancing sets forth the terms of transmission Procedures (LGIP),44 both the pro forma authorities, on average, to maintain service including, among other things, LGIA and SGIA are silent with respect Interconnection frequency, it does not the provision of ancillary services. to primary frequency response require generators to provide primary Additionally, the Commission adopted requirements. frequency response. In the rulemaking six ancillary services stating they are 27. In a final rule issued on January in which the Commission approved ‘‘needed to accomplish transmission 16, 2014, the Commission approved Reliability Standard BAL–003–1, some service while maintaining reliability Reliability Standard BAL–003–1, which commenters expressed concern that the within and among control areas affected establishes frequency response standard does not address the by the transmission service.’’ 38 The requirements for balancing availability of generator resources to ancillary service involved in this authorities.45 Reliability Standard BAL– provide primary frequency response or proceeding is Regulation and Frequency 003–1 established Interconnection the premature withdrawal 49 of primary Response Service, found in Schedule 3 Frequency Response Obligations that frequency response. In Order No. 794, of the pro forma OATT. prescribe the minimum frequency the Commission directed NERC to 23. In July 2003, the Commission response that must be maintained by an submit a report by July 2018 analyzing issued Order No. 2003, which revised Interconnection. The purpose of the the availability of resources for each the pro forma OATT to include a pro Interconnection Frequency Response balancing authority and Frequency forma LGIA, which applies to Obligation is to maintain the minimum Response Sharing Group 50 to meet their interconnection requests of large frequency (nadir) above UFLS set points Frequency Response Obligation.51 generators (i.e., generators larger than 20 following the largest contingency of the Furthermore, the Commission stated MW).39 While the pro forma LGIA Interconnection as defined by the that, if NERC learns that balancing adopted standard procedures and a resource contingency criteria in BAL– authorities are experiencing difficulty in standard agreement for the 003–1. Each balancing authority is procuring sufficient resources to satisfy interconnection of large generating assigned a Frequency Response their Frequency Response Obligations, facilities, it was ‘‘designed around the Obligation 46 that is a proportionate needs of large synchronous 42 Standardization of Small Generator 47 The Interconnection Frequency Response generators.’’ 40 The Commission also Interconnection Agreements and Procedures, Order Obligation and Frequency Response Obligation are added a blank Appendix G expressed in MW per 0.1 Hertz (MW/0.1 Hz). No. 2006, FERC Stats. & Regs. ¶ 31,180, order on 48 Attachment A of BAL–003–1. NERC will (Requirements of Generators Relying on reh’g, Order No. 2006–A, FERC Stats. & Regs. identify between 20 to 35 events annually in each Newer Technologies) to the LGIA to ¶ 31,196 (2005), order granting clarification, Order No. 2006–B, FERC Stats. & Regs. ¶ 31,221 (2006). Interconnection for calculating the Frequency serve as a means by which to apply 43 Reactive Power Requirements for Non- Response Measure. See also Procedure for ERO interconnection requirements specific Support of Frequency Response and Frequency Bias Synchronous Generation, 153 FERC ¶ 61,175 (2015). Setting Standard, (November 30, 2012), http:// for generators relying on newer 44 For example, in Order Nos. 661 and 661–A, the www.nerc.com/pa/Stand/Project%20200712%20 technologies, such as wind generators.41 Commission adopted standard procedures and Frequency%20Response%20DL/Procedure_Clean_ 24. In May 2005, the Commission technical requirements related to low voltage ride 20121130.pdf. thru and power factor design criteria for the issued Order No. 2006, which required interconnection of large wind plants, and required 49 NERC has stated that ‘‘[w]ithdrawal of primary all public utilities to adopt standard all public utilities that own, control, or operate frequency response is an undesirable characteristic facilities for transmitting electric energy in associated most often with digital turbine-generator interstate commerce to append Appendix G to their control systems using setpoint output targets for 37 Order No. 888, FERC Stats. & Regs. ¶ 31,036. LGIPs and LGIAs in their OATTs to include these generator output. These are typically outer-loop 38 Id. at 31,705. requirements. Interconnection for Wind Energy, control systems that defeat the primary frequency 39 Standardization of Generator Interconnection response of the governors after a short time to Order No. 661, FERC Stats. & Regs. ¶ 31,186, order Agreements and Procedures, Order No. 2003, FERC on reh’g, Order No. 661–A, FERC Stats. & Regs. return the unit to operating at a requested MW Stats. & Regs. ¶ 31,146, app. 6 (LGIP), app. C (LGIA) ¶ 31,198 (2005). output.’’ See Order No. 794, 146 FERC ¶ 61,024 at (2003), order on reh’g, Order No. 2003–A, FERC 45 Frequency Response and Frequency Bias P 65 (citing NERC’s Frequency Response Initiative mstockstill on DSK4VPTVN1PROD with NOTICES Stats. & Regs. ¶ 31,160, order on reh’g, Order No. Setting Reliability Standard, Order No. 794, 146 Report). 2003–B, FERC Stats. & Regs. ¶ 31,171 (2004), order FERC ¶ 61,024 (2014). Reliability Standards 50 NERC’s Glossary of Terms defines a Frequency on reh’g, Order No. 2003–C, FERC Stats. & Regs. proposed by NERC are submitted to the Response Sharing Group as a ‘‘group whose ¶ 31,190 (2005), aff’d sub nom. Nat’l Ass’n of Commission for approval pursuant to section 215(d) members consist of two or more Balancing Regulatory Util. Comm’rs v. FERC, 475 F.3d 1277 of the FPA; 16 U.S.C. 824o(d). Authorities that collectively maintain, allocate, and (D.C. Cir. 2007), cert. denied, 552 U.S. 1230 (2008). 46 NERC’s Glossary of Terms defines Frequency supply operating resources required to jointly meet 40 Order No. 2003–A, FERC Stats. & Regs. the sum of the Frequency Response Obligations of Response Obligation as ‘‘[t]he balancing authority’s ¶ 31,160 at P 407 & n.85. share of the required Frequency Response needed its members.’’ 41 Id. for the reliable operation of an Interconnection.’’ 51 Order No. 794, 146 FERC ¶ 61,024 at P 60. 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Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices 9187 NERC should immediately report it to 01 requires generator owners to operate requirements for all generating the Commission with appropriate each generating unit/generating facility resources (excluding nuclear units) with recommendations for mitigation.52 that is connected to the interconnected a gross plant/facility aggregate 29. Additionally, in Order No. 794, transmission system with the governor nameplate rating greater than 75 MVA.62 the Commission stated that the nature in service and responsive to frequency In addition, PJM recently added new and extent of the problems that could when the generating unit/generating interconnection requirements for result from the premature withdrawal of facility is online and released for interconnection customers entering its primary frequency response, and how dispatch, and to promptly notify the queue after May 2015 and seeking to best to address them, will be better balancing authority of any change in interconnect non-synchronous understood after NERC and balancing governor status.56 Additionally, BAL– generators, including wind generators, authorities have more experience with 001–TRE–01 requires generator owners to use ‘‘enhanced inverters’’ with the Reliability Standard BAL–003–1.53 The to set specified governor dead band and capability to, among other things, Commission also stated that the need to droop parameters.57 Moreover, BAL– provide primary frequency response.63 take action regarding the premature 001–TRE–01 requires generator owners PJM stated that the installed capacity of withdrawal of primary frequency to provide minimum initial and VERs in its region is expected to response, including requiring load sustained primary frequency response increase to approximately 15 GW by the controllers to include a frequency bias performance.58 NERC recently noted 2016–17 delivery year, and that it has an term to sustain frequency response or that ERCOT experienced a significant additional 25 GW of VERs in its otherwise modifying Reliability improvement in its frequency response interconnection queue.64 PJM expressed Standard BAL–003–1, should be performance as generators within its a need for VERs to install the capability decided after we have actual experience region adjusted their governor settings to automatically reduce or increase their with the Reliability Standard.54 for compliance with BAL–001–TRE– real power output in order to respond to 30. In light of the ongoing evolution 01.59 a variety of system conditions, of the nation’s generation resource mix, 33. ISO–NE requires each generator including high or low frequencies. PJM and other factors, such as NERC’s within its region with a capability of ten also stated that this capability will Generator Governor Industry Advisory MW or more, including renewable provide flexibility in responding to released in February 2015, the resources, to operate with a functioning transmission system events using all Commission believes that it is prudent governor with specified dead band and available resources which, according to to take a proactive approach to better droop settings, and to also ensure that PJM, will be increasingly important as understand the issues related to primary the provision of primary frequency VERs displace synchronous generators frequency response performance and response is not inhibited by the effects that have these capabilities.65 determine what additional actions of outer-loop controls.60 D. Compensation for Primary Frequency beyond Reliability Standard BAL–003–1 34. PJM has pro forma Response Service may be appropriate. Thus, the interconnection agreements that obligate interconnection customers within its 35. This section offers an overview of Commission is proceeding with a Notice region to abide by all PJM rules and Commission and industry action to date of Inquiry at this time rather than procedures pertaining to generation and related to compensation for primary waiting until NERC submits a report in transmission, including rules and frequency response. At present, there 2018. procedures set forth in the PJM are few, if any, entities receiving 31. In the absence of national primary Manuals.61 PJM requires large, compensation for selling primary frequency response requirements conventional generators to operate on frequency response as a stand-alone applicable to individual generating unrestricted governor control to assist in product, and there are no current rates resources, some areas, including maintaining Interconnection frequency, applicable to sales of primary frequency ERCOT, ISO New England Inc. (ISO– and recently established specified response alone. However, several NE), and PJM Interconnection, L.L.C. governor dead band and droop options for transactions involving (PJM), have implemented regional primary frequency response have been requirements for individual generating 693, the Commission approved a regional difference developed. Transmission providers may resources within their regions in order for the ERCOT Interconnection from Reliability sell primary frequency response service to maintain reliability. Standard BAL–001–0, allowing ERCOT to be in combination with regulation service 32. For example, the Commission exempt from Requirement R2, and found that under the bundled pro forma OATT accepted Texas Reliability Entity Inc.’s ERCOT’s approach to frequency response under its own market protocols appeared to be more stringent Schedule 3 product, Regulation and Regional Reliability Standard BAL–001– than Requirement R2. Order No. 693, FERC Stats. Frequency Response Service.66 TRE–01 (Primary Frequency Response & Regs. ¶ 31,242 at PP 313–315. in the ERCOT Region) as mandatory and 56 Reliability Standard BAL–001–TRE–01, at 62 PJM Manual 14D. enforceable, which places requirements Requirements R7 and R8. 63 PJM Interconnection, L.L.C., 151 FERC ¶ on generator owners and operators with 57 Reliability Standard BAL–001–TRE–01, at 61,097, at n.58 (2015). respect to the provision of primary Requirement R6. 64 PJM Interconnection, L.L.C., Transmittal Letter, 58 Reliability Standard BAL–001–TRE–01, at frequency response within the ERCOT Docket No. ER15–1193–000, at 2 (filed Mar. 6, Requirements R9 and R10. 2015). region.55 In particular, BAL–001–TRE– 59 NERC 2014 Frequency Response Annual 65 Id. at 11. Analysis Report at 6 (February 2015), http:// 66 Regulation service is different than primary 52 Id. P 63. www.nerc.com/FilingsOrders/us/ frequency response because regulation resources 53 Id. P 75. NERC%20Filings%20to%20FERC%20DL/Final_ respond to automatic generation control signals, mstockstill on DSK4VPTVN1PROD with NOTICES 54 Id. P 76. Info_Filing_Freq_Resp_Annual_Report_ which responds to Area Control Error. Regulation 55 North American Electric Reliability 03202015.pdf. See also Table 3 at 6. is centrally coordinated by the balancing authority. 60 Section I of ISO–NE’s Operating Procedure No. Corporation, 146 FERC ¶ 61,025 (2014). The Primary frequency response, in contrast, is requirements of BAL–001–TRE–01 help to ensure 14—Technical Requirements for Generators, autonomous and is not centrally coordinated. that generation and load remain balanced—or are Demand Resources, Asset Related Demands and Schedule 3 lumps these different services together, quickly restored to balance—in the ERCOT Alternative Technology Regulation Resources, despite their differences. The Commission in Order Interconnection so that system frequency is restored http://www.iso-ne.com/rules_proceds/operating/ No. 888 found that ‘‘while the services provided by to stability and near normal frequency even after a isone/op14/op14_rto_final.pdf. Regulation Service and Frequency Response Service significant event occurs on the system. In Order No. 61 PJM Tariff, Attachment O § 8.0. Continued VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 PO 00000 Frm 00027 Fmt 4703 Sfmt 4703 E:\FR\FM\24FEN1.SGM 24FEN1

9188 Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices Schedule 3 in the pro forma OATT in II. Request for Comments because no RTO/ISO currently defines Order Nos. 888 67 and 890 68 permits 37. The Commission seeks comment or procures such a product. As jurisdictional transmission providers to on the need for reforms to its rules and discussed below, the Commission seeks outline their rates for this regulation and regulations regarding the provision and comment on the need for and the nature frequency response service through a compensation of primary frequency of frequency response compensation filing under FPA section 205. Schedule response. Specifically, the Commission within the context of current RTO/ISO 3 charges are cost-based rates paid by seeks comment on possible actions to market optimization processes. transmission customers to the 40. Accordingly, the Commission ensure that the provision of primary transmission provider. Additionally, seeks comment on the following frequency response continues to remain Order No. 784 made it possible for possible actions, discussed in more at levels adequate to maintain the third-party sellers to offer Schedule 3 detail below: (1) Modifications to the reliability of the Bulk-Power System in service to the transmission provider at pro forma LGIA and SGIA mandating light of the ongoing transformation of a rate up to the published Schedule 3 primary frequency response the nation’s generation resource mix. rate, or at rates that result from an requirements for new resources, among The Commission understands that this appropriate competitive solicitation.69 other changes; (2) new primary transformation in the nation’s frequency response requirements for Such third-party sales could involve any generation portfolio could eventually existing resources; and (3) the combination of regulation and primary result in a reduction of system inertia requirement to provide and compensate frequency response services, including and fewer generation resources with for primary frequency response. unbundled primary frequency response primary frequency response capabilities. service by itself. A. Modifications to the pro forma LGIA 36. Finally, in Order No. 819, the In addition, as discussed above, NERC has indicated that a significant number and SGIA Commission revised its regulations to foster competition in the sale of primary of generators within the Eastern 41. Reliability Standard BAL–003–1 frequency response service.70 In the Interconnection utilize dead bands or and the pro forma LGIA and SGIA do final rule, the Commission approved the governor control settings that either not specifically address generators’ sale of primary frequency response inhibit or prevent the provision of provision of primary frequency service at market-based rates by entities primary frequency response. Together, response. Article 9.6.2.1 of the pro that qualify for market-based rate these factors could result in potential forma LGIA (Governors and Regulators) authority for sales of energy and downward shifts of the frequency nadir requires that if speed governors are capacity to any willing buyer. Order No. during disturbances, closer to UFLS set installed, they should be operated in 819 focused on how jurisdictional points that would trigger significant automatic mode.73 Reliability Standard entities can qualify for market-based widespread outages. BAL–003–1 and the pro forma LGIA and rates for primary frequency response 38. Presently, there are no pro forma SGIA do not explicitly: (1) Require service in the context of voluntary agreements for primary frequency generators to install the necessary bilateral sales, and did not place any response transactions. Voluntary sales capability to provide primary frequency limits on the types of transactions of primary frequency response, would response; (2) prescribe specific governor available to procure primary frequency most likely involve negotiated, bilateral settings that would support the response service; they may be cost- contracts between buyers and sellers. In provision of primary frequency based or market-based, bundled with this regard, considering their response; 74 or (3) establish generator other services or unbundled, and inside compliance obligations under primary frequency response or outside of organized markets.71 Order Reliability Standard BAL–003–1, performance requirements during No. 819 did not require any entity to balancing authorities will be the most disturbances (e.g., require the response purchase primary frequency response likely source of demand for voluntary to be sustained, and not prematurely from third parties or develop an purchases of primary frequency withdrawn prior to the initiation of organized market for primary frequency response service from third-party secondary frequency response actions to response.72 sellers, including those who have not return system frequency back to its provided the service in the past. nominal value and back within a are different, they are complementary services that Accordingly, as discussed further generator’s dead band setting).75 are made available using the same equipment. For below, the Commission seeks comment 42. The Commission’s pro forma this reason, we believe that Frequency Response on whether and to what extent generator interconnection agreements Service and Regulation Service should not be balancing authority demand for and procedures were developed at a offered separately, but should be offered as part of one service.’’ Order No. 888, FERC Stats. & Regs. voluntary purchases of frequency time when traditional generating ¶ 31,036, at PP 212–213 (1996). response would be reduced if all or all resources with standard governor 67 Order No. 888, FERC Stats. & Regs. ¶ 31,036. newly interconnecting resources were controls and large rotational inertia 68 Order No. 890, FERC Stats. & Regs. ¶ 31,241. required to provide frequency response were the predominant sources of 69 Third-Party Provision of Ancillary Services; service. Further, we also seek comment electricity generation. However, Accounting and Financial Reporting for New Electric Storage Technologies, Order No. 784, FERC on the impact this would have on the circumstances are evolving, with NERC Stats. & Regs. ¶ 31,349, at PP 6–7 (2013), order on Commission’s efforts under Order No. and others predicting significant clarification, Order No. 784–A, 146 FERC ¶ 61,114 819 to foster the development of a (2014). bilateral market for market-based rate 73 Order No. 2003, FERC Stats. & Regs. ¶ 31,146, 70 Third-Party Provision of Primary Frequency app. C (LGIA). sales of primary frequency response Response Service, Order No. 819, 153 FERC 74 Generator governors can be enabled or disabled mstockstill on DSK4VPTVN1PROD with NOTICES ¶ 61,220 (2015). service as a means of cost-effectively which determines whether or not primary 71 Id. P 13. meeting such demand. frequency response is provided at all by the 72 Id. P 37. The Commission denied Calpine 39. Within RTO/ISO markets, no generator. In addition, even if a governor is enabled, Corporation’s request for Regional Transmission current stand-alone primary frequency its control settings can limit the conditions under Organizations (RTOs) and Independent System response product exists. Any RTO/ISO which the generator provides primary frequency Operators (ISOs) to be given a deadline to develop response. tariff changes that would enable them to implement that desires to explicitly procure and 75 Primary frequency response would not be primary frequency response compensation compensate primary frequency response expected to be provided if no capacity (or mechanisms. would need new tariff provisions ‘‘headroom’’) is reserved on a unit. VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 PO 00000 Frm 00028 Fmt 4703 Sfmt 4703 E:\FR\FM\24FEN1.SGM 24FEN1

Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices 9189 retirements of conventional pursuant to NERC’s Primary Frequency 6.2. What changes, if any, to existing synchronous resources, all of which Control Guideline (i.e., droop infrastructure (including, but not contribute to system inertia, and some characteristics not to exceed 5 percent, limited to telemetry and software tools) of which provide primary frequency and dead band settings not to exceed would be required in order to verify response. In addition, VERs are ±0.036 Hz)? primary frequency response projected to comprise an increasing 1.3. Ensure that the MW response performance? portion of the installed capacity in provided (when there is available 6.3. What limitations based on many regions of the country, but they do headroom) in response to frequency resource type, if any, should be not typically provide inertial response deviations above or below the considered when evaluating primary or primary frequency response unless governor’s dead band from 60 Hz is: frequency response performance? specifically configured to do so. 1.3.1. Sustained until system 7. How would transmission providers 43. Regarding VERs, the Commission frequency returns to within the ensure compliance with the new rules? understands that in previous years, governor’s dead band setting? 7.1. Are penalties appropriate to many non-synchronous resources were 1.3.2. Provided without undue delay ensure that new generating resources not consistently designed with primary and responds in accordance with a adhere to the new requirements frequency response capabilities. specified droop parameter? described in question (1) above, and if However, NERC and others have stated 2. What are the costs associated with so, how should such penalties be that VER manufacturers have made making a newly interconnecting structured and implemented? significant advancements in recent years generation resource capable of 7.2. Are penalties appropriate only if to develop the necessary controls that providing primary frequency response? a resource receives compensation for would enable VERs to provide Specifically, what are the pieces of adhering to the new requirements frequency response.76 NERC equipment or software needed to described in question (1) above? recommends that the industry analyze provide primary frequency response, how wind and solar photovoltaic and what are the costs associated with B. New Primary Frequency Response resources can contribute to frequency those pieces of equipment or software? Requirements for Existing Resources response and to work toward Are there significant differences 46. The Commission seeks comment interconnection requirements that between synchronous and non- on how it might address the issue of ensure system operators will continue to synchronous resources in providing primary frequency response maintain essential reliability services.77 primary frequency response, (e.g., the performance in existing generators. As Also relevant are PJM’s recent additions type of equipment necessary)? discussed above, the Commission is of new interconnection requirements for 3. Regarding question (1) above, are considering amendments to the pro VERs entering its queue after May the governor control settings forma LGIA and SGIA that would apply 2015.78 PJM has stated that the recommended by NERC’s Primary prospectively and only to new necessary capabilities for non- Frequency Control Guideline the generating resources and not the synchronous resources to provide appropriate settings to include in the existing generating fleet. However, the primary frequency response, among pro forma LGIA and SGIA? Why or why Commission notes that NERC has also other services, are now ‘‘baked in’’ as not? expressed concerns related to the enhancements to inverter capabilities.79 4. Regarding new resources, including 44. In light of the ongoing changes in primary frequency response non-synchronous resources, are there performance of the existing generating the nation’s resource mix as well as physical, technical, or operational NERC’s concerns regarding the primary fleet. limitations/concerns to promptly frequency response performance of 47. For example, in 2010, NERC providing sustained primary frequency existing resources, the Commission conducted a governor response survey response in the direction necessary to seeks comment on whether and how to to gain insight into governor settings counteract under-frequency and over- modify the pro forma LGIA and SGIA to from several turbine governors across frequency deviations? How should new require primary frequency response the three U.S. Interconnections.80 requirements account for such capability and performance of new Analysis revealed a wide disparity in limitations? generating resources. the reported governor control settings. 5. Are metrics or monitoring useful to 45. To that end, the Commission seeks For example, NERC found that several evaluate whether new resources: comment on the following questions: generator owners or operators reported 5.1. Operate with governors (or dead bands between 0.05 Hz and 0.3 Hz, 1. Should the pro forma LGIA and equivalent frequency control devices) which are wider than those prescribed SGIA be revised to include requirements enabled? by ERCOT’S BAL–001–TRE–01 Regional for all newly interconnecting generating 5.2. Set governor control settings as Standard or recommended by NERC’s resources, including non-synchronous described in question (1) above? 2015 Generator Governor Frequency resources, to: 1.1. Install the capability necessary to 5.3. Provide sustained MW response Response Industry Advisory 81 and provide primary frequency response? (when the unit has available headroom Primary Frequency Control Guideline.82 1.2. Ensure that prime mover and system frequency deviates outside 48. In February 2015, NERC issued an governors (or equivalent frequency of the dead band) that is in the direction Industry Advisory, which expressed its control devices) are enabled and set necessary to correct the frequency determination that a significant portion deviation and responsive in accordance of generators within the Eastern mstockstill on DSK4VPTVN1PROD with NOTICES 76 NERC Long Term Reliability Assessment at 27 with a specified droop parameter? Interconnection utilize governor dead (November 2014), http://www.nerc.com/pa/RAPA/ 6. How would transmission providers bands or other control settings that ra/Reliability%20Assessments%20DL/2014LTRA_ verify that new resources provide ERATTA.pdf. adequate primary frequency response 77 Id. 80 Frequency Response Initiative Report at 87. 78 PJM Interconnection, L.L.C., 151 FERC ¶ performance? 81 NERC Generator Governor Frequency Response 61,097, at n.58 (2015). 6.1. What information is necessary in Industry Advisory. 79 PJM Interconnection, L.L.C., Docket No. ER15– order to facilitate performance 82 NERC Primary Frequency Control Guideline 1193–000 (March 6, 2015) Transmittal Letter at 11. verification? Final Draft. VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 PO 00000 Frm 00029 Fmt 4703 Sfmt 4703 E:\FR\FM\24FEN1.SGM 24FEN1

9190 Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices either inhibit or prevent the provision of 51. As noted above, in December C. Requirement to Provide and primary frequency response.83 2015, NERC’s Operating Committee Compensate for Primary Frequency 49. Furthermore, some generating approved a Primary Frequency Control Response Service units have controls that withdraw Guideline that contains recommended 53. Without the explicit requirement primary frequency response prior to the settings for generator governors and to provide primary frequency response initiation of secondary frequency other plant control systems, and or appropriate compensation for the controls, which is a significant concern encourages generators within the three provision of such service, resource in the Eastern Interconnection and a U.S. Interconnections to provide owners may choose to disable or somewhat smaller issue in the Western sustained and effective primary otherwise reduce the provision of Interconnection. These controls are primary frequency response from their frequency response during major grid known as outer-loop controls to existing resources or not install the events in order to stabilize and maintain distinguish them from more direct, equipment on their new resources.90 lower-level control of the generator system frequency within allowable limits.89 However, the Commission 54. The Commission seeks operations. Primary frequency response information on whether there is a need withdrawal occurs when outer-loop notes that NERC’s Primary Frequency Control Guideline is not mandatory and to establish or modify procurement and controls deliberately act to nullify a compensation mechanisms for primary generator’s governor response and enforceable and does not alter any frequency response, and whether these return the unit to operate at a pre- approved Reliability Standards. mechanisms will ensure that the disturbance scheduled MW output. This 52. In light of the above discussion, resulting rates are just and reasonable. is especially problematic when it occurs the Commission seeks to further explore The Commission invites commenters to prior to the activation of secondary issues regarding the provision of share their overall views, including the response, and has the potential to primary frequency response by the operational, technical and commercial degrade the overall response of the existing generation fleet and seeks impacts that may result from mandates Interconnection and result in a comment on the following questions: to provide primary frequency response. frequency that declines below the To that end, the Commission seeks original nadir. NERC has observed that 1. Should the Commission implement comment on the following questions: early withdrawal of primary frequency primary frequency response 1. Should all resources be required to response continues to occur within the requirements for existing resources, as provide minimum levels of: (1) Primary Eastern Interconnection.84 discussed above for new generators? If frequency response capability; and (2) 50. Furthermore, NERC’s Resources so, what is an appropriate means of primary frequency response Subcommittee has determined that the doing so (e.g., changes to transmission performance in real-time? majority of gas turbines operate in some provider tariffs or improvements to 1.1. ‘‘Capability’’ involves having a type of MW Set Point control mode.85 existing reliability standards)? How turbine governor or equivalent According to the NERC Resources would transmission providers ensure equipment that has the ability to sense Subcommittee, the Eastern that existing resources adhere to new changes in system frequency, and is Interconnection Initiative has uncovered primary frequency response enabled and set with appropriate that in order for gas turbines to respond requirements? governor settings (e.g., droop and dead in MW Set Point control mode, an 2. As noted above, some existing band), and assuming capacity (or additional frequency algorithm has to be ‘‘headroom’’) has been set aside, the generating units set dead bands wider installed.86 Moreover, NERC’s physical ability to ramp the resource than those recommended by NERC’s Resources Subcommittee stated that quickly enough in order to provide ‘‘the net result is that the gas turbine Primary Frequency Control Guideline, useful levels of primary frequency fleet that has been installed in the past and some units have control settings set response to help arrest the frequency 20+ years is not frequency responsive, in a manner that results in the deviation. [which] has to be corrected.’’ 87 NERC premature withdrawal of primary 1.2. ‘‘Performance’’ would involve has also observed that in many frequency response. Should the putting the ‘‘capability’’ into actual conventional steam plants, dead band Commission prohibit these practices? If service: i.e., actually operating the settings exceed the maximum ±0.036 Hz so, by what means? resource with governors or equivalent dead band, and the resulting response is 3. What are the costs of retrofitting equipment enabled, ensuring that squelched and not sustained.88 existing units, including non- governor controls (e.g., droop and dead synchronous resources, and with band) and other settings are properly set 83 NERC Generator Governor Frequency Response specific reference to such factors as and coordinated, such that when Industry Advisory. capacity (or ‘‘headroom’’) has been set 84 NERC 2015 Frequency Response Annual equipment types and MW capacity, to be capable of providing sustained aside, the unit promptly provides Analysis Report at vi (September 2015), http:// www.nerc.com/comm/OC/ primary frequency response? sustained primary frequency response RS%20Landing%20Page%20DL/Related%20Files/ during frequency excursions, until 2015_FRAA_Report_Final.pdf. 4. Regarding existing units, are there system frequency returns to within the 85 See News from SERC’s NERC Resources physical, technical, or operational governor’s dead band setting. Subcommittee Rep—Primary Frequency Response limitations or concerns to promptly at 1 (May 2015), https://www.serc1.org/docs/ 2. Is it necessary for every generating default-source/outreach/communications/resource- providing sustained primary frequency resource to install the capability documents/serc-transmission-reference/201505---st/ response in the direction necessary to necessary to provide primary frequency mstockstill on DSK4VPTVN1PROD with NOTICES primary-frequency-response.pdf?sfvrsn=2. MW set- counteract under-frequency and over- point control mode automatically interrupts governor response in order for a generating unit to frequency deviations? 90 IEEE, Interconnected Power System Response to Generation Governing: Present Practice and maintain a pre-disturbance dispatch. Outstanding Concerns (May 2007) (citing Cost of 86 Id. pa/rrm/Webinars%20DL/Generator_Governor_ Providing Ancillary Services from Power Plants— 87 Id. Frequency_Response_Webinar_QandA_April_ Volume 1: A Primer, EPRI TR–1 07270–V1, 4161, 88 See NERC Generator Governor Frequency 2015.pdf. Final Report, March 1997), http:// Response Advisory—Webinar Questions and 89 NERC Primary Frequency Control Guideline resourcecenter.ieee-pes.org/pes/product/technical- Answers at 1 (April 2015), http://www.nerc.com/ Final Draft. reports/PESTR13. VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 PO 00000 Frm 00030 Fmt 4703 Sfmt 4703 E:\FR\FM\24FEN1.SGM 24FEN1

Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices 9191 response? Or is it more appropriate for resources chosen by an optimization Schedule 3 and creating a separate balancing authorities to identify and algorithm actually enable governor ancillary service covering each procure the amount of primary controls with appropriate governor individually? If so, how should a new frequency response service that they settings so that they provide sustained pro forma Primary Frequency Response need to meet their obligations under primary frequency response when Ancillary Service be structured? Reliability Standard BAL–003–1 and the capacity (or ‘‘headroom’’) has been 7. When compensating for primary optimum mix of resources to meet that reserved and frequency deviates outside frequency response, should need? of their dead band settings? compensation be different inside and 2.1. To the extent that balancing 3. If generation resources were outside of RTOs/ISOs? authorities are responsible for procuring required to have minimum levels of 8. What procurement requirements or adequate primary frequency response primary frequency response capability compensation mechanisms could be service, does the current framework for or performance, should such resources used for primary frequency response blackstart provide a useful guide for be compensated for providing primary from stored energy resources? When how primary frequency response service frequency response capability, considering requirements or could be procured? performance, or both? If so, why? If not, compensation for stored energy 2.2. Does the Commission’s recent why? resources, how should possible rulemaking allowing third-party sales of 3.1. If payment is based on capacity additional costs or other concerns be frequency response services at market (or ‘‘headroom’’) that is set aside for addressed? based rates allow balancing authorities primary frequency response, how to procure sufficient amounts of primary should such a capacity payment be III. Comment Procedures frequency response as required by BAL– structured and determined? 55. The Commission invites interested 003–1? 3.2. If payment is based on actual persons to submit comments, and other 2.3. To the extent that balancing performance, either alone or in information on the matters, issues and authorities centrally optimize primary combination with a capacity-based specific questions identified in this frequency response, wherein an payment, please discuss possible rate notice. Comments are due April 25, algorithm optimizes in the operating structures applicable to primary 2016. Comments must refer to Docket horizon the set of resources in which to frequency response performance. No. RM16–6–000, and must include the allocate primary frequency response 3.3. Will a market price provide commenter’s name, the organization headroom: Should all newly resources with sufficient incentive to they represent, if applicable, and their interconnecting resources be required to invest in primary frequency response address in their comments. install the necessary capability in these capability and make the service 56. The Commission encourages areas? Can balancing authorities predict available to the balancing authority in comments to be filed electronically via far ahead of the operating horizon the real-time, absent a requirement that the eFiling link on the Commission’s least-cost set of resources from which it resources maintain the capability to Web site at http://www.ferc.gov. The will optimize the provision of primary provide primary frequency response and Commission accepts most standard frequency response? perform as required? 2.4. Would the costs of requiring all word processing formats. Documents 4. Currently, how do RTOs/ISOs resources to have the capability to created electronically using word ensure that they have the appropriate provide primary frequency response be processing software should be filed in amount of primary frequency response significantly greater than the costs that native applications or print-to-PDF capability during operations? would result from an Interconnection- 4.1. Are resources contracted for format and not in a scanned format. wide or balancing authority-wide primary frequency response outside of Commenters filing electronically do not optimization of which generators should the market optimization and dispatch? need to make a paper filing. be capable of providing primary 4.2. Alternatively, does the market 57. Commenters that are not able to frequency response? optimization and dispatch incorporate file comments electronically must send 2.5. Would the costs of requiring all primary frequency response in its an original of their comments to: new resources to enable and set their optimization? Federal Energy Regulatory Commission, governors, or equivalent equipment, to 5. Would it be appropriate for RTOs/ Secretary of the Commission, 888 First be able to provide primary frequency ISOs to create a product for primary Street NE., Washington, DC 20426. response in real-time be significantly frequency response service? 58. All comments will be placed in greater than the costs that would result 5.1. Should this product be similar to the Commission’s public files and may from an Interconnection-wide or a capacity product for the procurement be viewed, printed, or downloaded balancing authority-wide optimization of primary frequency response remotely as described in the Document of which generators should provide capability from resources? Availability section below. Commenters primary frequency response in real- 5.2. Should this product be similar to on this proposal are not required to time? other ancillary service products in serve copies of their comments on other 2.6. Please discuss the viability of which certain resources would be commenters. implementing an Interconnection-wide selected in the day-ahead or real-time IV. Document Availability optimization mechanism. markets to provide primary frequency 2.7. Would requiring every resource to response? 59. In addition to publishing the full be capable of providing primary 5.3. Are there benefits to co- text of this document in the Federal mstockstill on DSK4VPTVN1PROD with NOTICES frequency response result in over- optimizing the capacity (or Register, the Commission provides all procurement or inefficient investment ‘‘headroom’’) allocated on generating interested persons an opportunity to in primary frequency response units for primary frequency response view and/or print the contents of this capability to the detriment of with the market optimization and document via the Internet through customers? dispatch of RTOs/ISOs? If so, what are FERC’s Home Page (http:// 2.8. Without rules to compel the challenges associated with doing so? www.ferc.gov) and in FERC’s Public performance, how would balancing 6. Are there benefits to separating Reference Room during normal business authorities ensure that the optimal set of Frequency Response Service under hours (8:30 a.m. to 5:00 p.m. Eastern VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 PO 00000 Frm 00031 Fmt 4703 Sfmt 4703 E:\FR\FM\24FEN1.SGM 24FEN1

9192 Federal Register / Vol. 81, No. 36 / Wednesday, February 24, 2016 / Notices time) at 888 First Street NE., Room 2A, percent along with a rate of return of DEPARTMENT OF ENERGY Washington, DC 20426. 5.77 percent are calculated with the per- 60. From FERC’s Home Page on the acre land values less the state-specific Federal Energy Regulatory Internet, this information is available on reduction to derive at the individual Commission eLibrary. The full text of this document state/county per-acre federal land rates is available on eLibrary in PDF and assessed to hydropower projects. Notice Revising Post-Technical Microsoft Word format for viewing, Conference Comment Schedule The FY 2016 federal lands fee printing, and/or downloading. To access schedule rates have significantly Docket Nos. this document in eLibrary, type the increased in comparison to the FY 2015 docket number excluding the last three PJM Interconnection, L.L.C ... ER15–2562–000, digits of this document in the docket federal lands fee schedule rates issued ER15–2563–000. number field. on January 8, 2015 for a number of Consolidated Edison Com- EL15–18–001. 61. User assistance is available for hydropower projects located in multiple pany of New York, Inc. v. states/counties. In particular, PJM Interconnection, L.L.C. eLibrary and the FERC’s Web site during Linden VFT, LLC v. PJM EL15–67–000. normal business hours from FERC hydropower projects located in the Interconnection, L.L.C. Online Support at 202–502–6652 (toll Kenai Peninsula Area of Alaska land Delaware Public Service EL15–95–000. free at 1–866–208–3676) or email at rates increased by 71 percent in Commission and Maryland Public Service Commission ferconlinesupport@ferc.gov, or the comparison to land rates assessed in FY v. PJM Interconnection, Public Reference Room at (202) 502– 2015. The FY 2016 increase of per-acre L.L.C. 8371, TTY (202) 502–8659. Email the land rates was mainly attributed to the PJM Interconnection, L.L.C ... ER14–972–003. increase of per-acre land and building PJM Interconnection, L.L.C ... ER14–1485–005, Public Reference Room at Not Consolidated. public.referenceroom@ferc.gov. values published in the 2012 NASS By direction of the Commission. Census. The per-acre land value for land in the Kenai Peninsula Area was In an order dated November 24, Issued: February 18, 2016. 2015,1 the Commission found that the increased from $1,328 in the 2007 NASS Nathaniel J. Davis, Sr., assignment of cost allocation for the Census to $2,423 in the 2012 NASS Deputy Secretary. projects in the filings and complaints Census. This increase along with [FR Doc. 2016–03837 Filed 2–23–16; 8:45 am] listed in the caption using PJM’s factoring in the state-specific reduction, solution-based distribution factor BILLING CODE 6717–01–P the 50 percent encumbrance factor, and (DFAX) cost allocation method had not the 5.77 percent rate of return ultimately been shown to be just and reasonable resulted in a 71 percent increase of per- DEPARTMENT OF ENERGY and may be unjust, unreasonable, or acre land rates assessed to hydropower unduly discriminatory or preferential. Federal Energy Regulatory projects located in the Kenai Peninsula The Commission directed its staff to Commission Area. In addition, per-acre land values establish a technical conference to for San Bernardino County located in [Docket No. RM11–6–000] explore both whether there is a California, Boulder and Clear Creek definable category of reliability projects Counties located in Colorado, and Billing Procedures for Annual Charges within PJM for which the solution-based Blaine County located in Idaho all for Recompensing the United States DFAX cost allocation method may not significantly increased as a result of the for the Use, Occupancy, and be just and reasonable, such as projects 2012 published NASS Census. Enjoyment of Federal Lands; Notice of addressing reliability violations that are Statement of Annual Charges for the Conversely, the FY 2016 federal lands not related to flow on the planned Use of Government Lands for Fiscal fee schedule rates have significantly transmission facility, and whether an Year 2016 decreased in comparison to the FY 2015 alternative just and reasonable ex ante federal lands fee schedule rates issued cost allocation method could be By this notice, the Commission states on January 8, 2015 for a number of established for any such category of that in accordance to the Final Rule hydropower projects located in other projects. issued on January 17, 2013 1 the federal locations as a result of the decreased The technical conference was held on lands fee schedule of per-acre rates have per-acre land values published in the January 12, 2016. At the technical been calculated for Fiscal Years (FY) 2012 NASS Census. Specifically conference, staff indicated that it would 2016 through 2020. Pursuant to the hydropower projects occupying federal establish a schedule for post-technical Final Rule, the Commission re- lands in Alpine, Lake, and Riverside conference comments after reviewing calculates the federal lands fee schedule Counties located in California, Aleutian the technical conference transcript. On every five years by using the per-acre Islands Area located in Alaska, and February 9, 2016 a technical conference land values published in the National Grays Harbor County located in transcript was place in the above- Agricultural Statistics Service (NASS) Washington will receive as much as a 37 referenced dockets, and a post-technical Census. The Commission established percent decrease in comparison to the conference comment schedule was the FY 2016 through FY 2020 federal federal lands annual charges issued in established. On February 18, 2016, an lands fee schedule based on data FY 2015. errata transcript of the February 9, 2016 published in the 2012 NASS Census. In If you have any questions regarding transcript was placed in the dockets. addition, the Commission determines a this notice, please contact Steven The schedule for post-technical state-specific reduction that removes the mstockstill on DSK4VPTVN1PROD with NOTICES Bromberek at (202) 502–8001 or Norman conference comments is revised value of irrigated lands on a state-by- Richardson at (202) 502–6219. accordingly. state basis, plus a seven percent reduction to remove the value of Dated: February 18, 2016. Post-technical conference comments, buildings. An encumbrance factor of 50 not to exceed 20 pages, are due on or Nathaniel J. Davis, Sr., before March 9, 2016. Deputy Secretary. 1 Annual Charges for Use of Government Lands, [FR Doc. 2016–03829 Filed 2–23–16; 8:45 am] Final Rule, Order No. 774, 78 FR 5256 (January 25, 1 PJM Interconnection, L.L.C., et al., 153 FERC ¶ 2013), 142 FERC Stats & Regs. ¶ 61,045 (2013). BILLING CODE 6717–01–P 61,245 (2015). VerDate Sep<11>2014 17:59 Feb 23, 2016 Jkt 238001 PO 00000 Frm 00032 Fmt 4703 Sfmt 4703 E:\FR\FM\24FEN1.SGM 24FEN1


Document Created: 2016-02-23 23:55:38
Document Modified: 2016-02-23 23:55:38
CategoryRegulatory Information
CollectionFederal Register
sudoc ClassAE 2.7:
GS 4.107:
AE 2.106:
PublisherOffice of the Federal Register, National Archives and Records Administration
SectionNotices
ActionNotice of Inquiry.
DatesComments are due April 25, 2016.
ContactJomo 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]
FR Citation81 FR 9182 
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