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California ISO Frequency Response – Issue Paper

CAISO/M&ID/JC 1 August 7, 2015

Frequency Response

Issue Paper

August 7, 2015

Market and Infrastructure Policy



Table of Contents 1. Purpose of this initiative .................................................................................................................... 3

2. Background ......................................................................................................................................... 4

2.1. Primary Response to a Frequency Disturbance ........................................................................ 4

2.2. Frequency Response Trend in North America .......................................................................... 7

2.3. ISO Frequency Response Capabilities ....................................................................................... 9

3. Details of ISO Frequency Response Obligation under BAL-003-1 .......................................... 11

4. Considerations for the ISO.............................................................................................................. 12

5. Initiative Schedule ............................................................................................................................ 14

6. Next Steps ......................................................................................................................................... 14



1. Purpose of this initiative

On January 16, 2014, the Federal Energy Regulatory Commission (FERC) approved1 Reliability

Standard BAL-003-12 (Frequency Response and Frequency Bias Setting), submitted by the

North American Reliability Corporation (NERC). With the approval of this standard, NERC

created a new obligation for balancing authorities including the ISO to demonstrate sufficient

frequency response to disturbances in system frequency. The purpose of this initiative is to

ensure that the ISO can comply with the new NERC requirements.

To assess each balancing authority’s performance, on an annual basis NERC will select

between 20 and 30 disturbance events within the year and measure the balancing authority’s

response to each disturbance.3 In 2013, there were 25 such events.

Compliance with BAL-003-1 will begin December 1, 2016.4 NERC has established a

methodology for calculating frequency response obligations. NERC determines a balancing

authority’s obligation by first determining the obligation for the interconnection as a whole and

then assigning a share to each balancing authority based on its share of the total generation

and load of the interconnection. As a balancing authority in the Western Electricity Coordinating

Council (WECC), the ISO will have between 24% and 30% of WECC’s total frequency response

1 See FERC Order No. 794 Docket No. RM13-11-000 2 See Reliability Standard BAL-003-1 3 Event selection details are covered within this NERC filing. 4 The standard goes into effect on April 1, 2016, but NERC will not begin measuring compliance until December 1, 2016.

NERC’s BAL-003-1 Frequency Response and Frequency Bias Setting

Purpose: To require sufficient Frequency Response from the BA to maintain Interconnection

Frequency within predefined bounds by arresting frequency deviations and supporting frequency

until the frequency is restored to its scheduled value. To provide consistent methods for

measuring Frequency Response and determining the Frequency Bias Setting.

Requirement R1 of BAL-003-1 requires that each BA or Frequency Response Sharing Group (FRSG) must achieve an annual Frequency Response Measure that is equal to or more negative than its “Frequency Response Obligation” to ensure sufficient Frequency Response.

http://www.ferc.gov/whats-new/comm-meet/2014/011614/E-2.pdf

http://www.nerc.com/pa/Stand/Reliability%20Standards%20Complete%20Set/RSCompleteSet.pdf

http://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Final_Info_Filing_Freq_Resp_Annual_Report_03202015.pdf



obligation. WECC’s obligation5 is 906 MW/0.1 Hz and therefore the ISO’s obligation is

218 MW/0.1 Hz.

Compliance with the frequency response obligation is based on actual performance, rather than

procurement of frequency response capability. Accordingly, this standard requires the ISO to

demonstrate that resources provided sufficient frequency response during frequency

disturbance events. At the same time, in order to be prepared for unpredictable frequency

events, the ISO will need some procedure to ensure that sufficient frequency response is

available to meet the ISO’s share of WECC’s obligation whenever such an event occurs. This

paper summarizes the ISO’s current capability to respond to frequency response events and

considers whether this capability will enable the ISO to comply with the new standard. The ISO

seeks stakeholder input on how best to meet the new requirement and on the frequency

response capabilities of emerging technologies such as wind, solar and energy storage devices.

2. Background

This section provides general background on frequency response and the difference between

primary, secondary and tertiary frequency controls. The new NERC standard addresses the

primary frequency control referred to as “frequency response.” This section also describes the

ISO’s current capabilities for primary, secondary and tertiary response.

2.1. Primary Response to a Frequency Disturbance

Frequency response is the initial or primary response of resources and load to arrest and

quickly recover from changes in system frequency. During normal operating conditions, system

frequency is close to scheduled frequency (typically 60 Hz) and is essentially the same

throughout an interconnection. All balancing authorities within an interconnected electric

system are responsible to provide frequency response capability to support system frequency in

the event of a disturbance. The loss of a major resource can cause system frequency to decline

to unacceptable operating levels, risking unintentional tripping of load and damage to large

steam turbines. Historically, frequency response – the primary and most immediate response to

the disturbance – has mainly been provided by the governor response of conventional turbine

generators, which comprised the vast majority of generating resources, and frequency

responsive loads. In contrast, resources such as wind and solar generating facilities, storage

devices and non-frequency responsive loads typically do not have the automatic governor

5 Subject to changes by NERC



response common to conventional generators. With modern inverters, however, these

resources can provide inertia6 and frequency response.

Following a disturbance, the total frequency response from all resources will support a

balancing authority’s ability to meet its frequency response obligation to the interconnection.

When a balancing authority loses a resource, it causes a sudden drop in frequency which is

detected by the governors on other resources within the interconnection. The governors then

provide immediate support to stabilize frequency by increasing the amount of energy their

respective resources deliver to the grid. Similarly, frequency responsive loads such as motors

and inductive loads consume less power in response to a frequency drop. Figure 1 illustrates

how primary frequency control (frequency response), in conjunction with secondary control (i.e.,

automatic generation control or regulation service) and tertiary control (i.e., market or operator

dispatch) work to restore scheduled frequency following a disturbance.

6 Inertia is a characteristic of massive spinning turbines, which has the effect of slowing or inhibiting a change in frequency. Whereas frequency response can be thought of as the response of resources to a change in frequency, inertia works to moderate the initial magnitude of the frequency change.



Figure 1 - Frequency Response

7 Source- NERC Frequency Response Initiative

An example of such a decline is illustrated in Figure 2, including points relevant to measuring

frequency response.

7 See NERC Frequency Response Initiative

http://www.nrel.gov/electricity/transmission/pdfs/cummings.pdf



Figure 2 - Frequency Response

Point A indicates system frequency just prior to a disturbance, which occurs at time T0. Within

the first 30 seconds following the disturbance, balancing authorities within the interconnection

provide frequency response to arrest system frequency (i.e., from T0 to point C) and stabilize the

system (i.e., between Point C and one minute after T0).

2.2. Frequency Response Trend in North America

Since the 1960s generation technology has transitioned from almost exclusively hydro and

steam turbine generators to a more diverse fleet of resource types operating today. This

transition has contributed to the reduction of conventional governor response and as the

resource fleet undergoes a rapid transition the ISO expects governor response to continue to

decline. Different unit types exhibit different governing response characteristics8. Nuclear units

exhibit little to no governor response, while large hydro plants generally exhibit a significant

response in the correct direction. NERC published the Frequency Response Initiative Report

8 See IEEE Power & Energy Society’s PES-TR13 Report

Point A

Point C

Point B

1-Minuteafter T0

59.90

59.92

59.94

59.96

59.98

60.00

60.02

0 4 8 12 16 20 24 28 32 36 40 44 48 52 56 60 64 68 72 76 80 84 88 92 96

Hz

Seconds

FrequencyFREQ

T0

http://resourcecenter.ieee-pes.org/files/2013/11/TR13_TP180_Full_Content.pdf



20129 with the intention of achieving a better understanding of the factors influencing frequency

performance across North America.

Apart from the change in generating resource mix to more non-conventional resources, several

economic reasons exist for conventional generating units to operate in ways that prevent

effective governor response. For example, if a unit operates at its maximum capability,

regardless of control mode the unit cannot provide additional power in response to a downward

disturbance in frequency. Another example is outer-loop megawatt control, which inhibits

governor response by slowly adjusting the governor load reference in order to maintain a pre-

selected megawatt level, for example, to maintain the resource’s day-ahead energy schedule.

The National Renewable Energy Laboratory (NREL) has noted10 general concern exists among

power system operators and utilities regarding the degradation of frequency response in North

America over the past two decades. The decline is attributed to several factors. These factors

include the withdrawal of primary or governor response shortly after an event, insufficient in-

service governors on conventional generation, and the unknown and changing nature of load

frequency characteristics. The NREL report also notes increased penetration of inverter-based,

or non-synchronous, generation technologies, which lack conventional governor controls. As a

result, dynamic performance changes due to increased wind and solar generation, combined

with reduced frequency response capability of the fleet, may further complicate integration of

renewable generation.

There are several logical reasons why frequency response is declining. Among them are:

Steam turbine-generators operating on traditional “sliding pressure” control;

Significant penetration of non-traditional generation, primarily wind and solar generation;

Proportionally fewer frequency-responsive large motor loads, as the US becomes less of an industrial economy;

Variable speed drives on motors do not provide traditional load damping;

Some combustion turbine generator designs actually have a positive frequency characteristic, i.e., their output MWs go down when frequency drops. As frequency drops, turbine and compressor speeds drop, airflow decreases, with correspondingly less available for combustion. The manufacturer intentionally reduces fuel input when frequency drops to prevent overheating. This phenomenon reportedly contributed to a blackout in Malaysia in 1996;

Generators having less inertia (less mass per MW of output);

Fewer resources are carrying frequency responsive spinning reserves as the rules for the distribution of reserves have been relaxed; and

9 See NERC Frequency Response Initiative Report 2012 10 See Western Wind and Solar Integration Study Phase 3 – Frequency Response and Transient Stability

http://www.nerc.com/docs/pc/FRI_Report_10-30-12_Master_w-appendices.pdf

http://www.nrel.gov/docs/fy15osti/62906-ES.pdf



Power plant control interaction removing or withdrawing governor action due to outer loop control which may be due to focus on plant performance with generation set points.

The automatic generation control (AGC) function can also reduce the frequency response of a

resource. If AGC perceives a resource’s response to a frequency excursion as a deviation from

an economic or market-determined set-point, it would attempt to reverse the frequency

response and return the resource to its economic target.

2.3. ISO Frequency Response Capabilities

The ISO currently meets frequency response through various system characteristics and

products as summarized in the table below. For example, inertial response is a characteristic of

the system typically provided by the rotating mass of conventional generation. During a

frequency disturbance, the inertia of these resources naturally counteracts and thus reduces the

magnitude of the deviation in frequency. This does not require action by either the system

operator or a governor; it is inherent to the nature of the unit characteristics. Over time, as

nonconventional generation replaces conventional generation, the ISO fleet as a whole may

lose natural inertial response.

Primary response is provided by governor control of synchronous generators and frequency

responsive loads. Currently, the WECC has specified “droop” settings for conventional

generators. The droop setting of the governor determines the MW amount a generator

responds for each unit of frequency change. This response is instantaneous and automatic

from each resource and does not require operator action. However there is no corresponding

requirement for non-conventional generators. For primary response, the ISO currently does not

have a procurement target. Generators can provide primary frequency response if they are

operating below their maximum operating capacity and have available headroom. The ISO’s

procurement of spinning reserves ensures that generators have headroom in case of a

contingency.11

Secondary response is provided by resources under automatic generation control. The

response is slower than primary response, but still may occur within seconds to minutes. The

ISO procures regulation up and down to maintain balance between supply and demand within

each 5 minute dispatch interval. These resources are on automatic generation control and can

also serve as secondary frequency response.

Tertiary response requires system operator dispatch control. This occurs within minutes after

the start of the event. The ISO deploys spinning and non-spinning reserves to address

contingencies and frequency disturbances.

11 See ISO tariff Appendix K for spinning reserve minimum governor characteristics.

http://www.caiso.com/Documents/AppendixK_AncillaryServiceRequirementsProtocolASRP_Jan1_2015.pdf



Response

Type

Inertial response Primary response Secondary

response

Tertiary

Response

Provided by • Comes from

motors, pumps,

and

conventional

generators

• It is more a

characteristic of

the system

• As the ISO loses

more

conventional

generator, will

have less inertial

response

• Comes largely

from

conventional

generators

with governor

response

installed and

tuned based

on WECC

requirements

• Most

intermittent do

not have

technology

• Comes from

generation

under

automatic

generation

control

• Comes from

generators

dispatched

through

operator

control.

Response

Time

• Response in

seconds

• Autonomous

(not ISO

controlled)

response in

seconds

• ISO

controlled

response in

minutes

• ISO controlled

response in

minutes

The ISO

Procurement

• The ISO does

not explicitly

procure

• The ISO does

not explicitly

procure, but

resources with

available

headroom may

respond, such

as spinning

reserves

• Upward and

downward

regulation

• Dispatch of

real-time

imbalance

energy and

deployment of

spinning and

non-spinning

reserves



3. Details of ISO Frequency Response Obligation under BAL-003-1

Currently, the ISO does not explicitly procure frequency response capability. The ISO assumes

it is provided through adherence to the WECC standard for governor droop settings and the

automatic governor response of interconnected generating resources.12 Compliance with the

new standard will be measured based upon actual response of generators and load. Therefore,

any solution adopted by the ISO and stakeholders must ensure obligated units respond

appropriately.

If the standard were in place today, the ISO’s 2016 share of frequency response for the loss of

two Palo Verde units would be approximately 775 MW of upward response. Every year NERC

will establish each BA’s frequency response obligation, which is an all hours (24x7)

requirement.13 The ISO has therefore opened the present initiative to determine how best to

meet the new obligation.

Figure 3 compares the ISO’s frequency response performance with the new obligation had this

been in place for 2013.

Figure 3 - 2013 Frequency Response

12 Automatic response by generator governors is different from AGC. 13 See BAL-003-1 Attachment A for NERC’s methodology

http://www.nerc.com/pa/Stand/Reliability%20Standards%20Complete%20Set/RSCompleteSet.pdf



4. Considerations for the ISO

Compliance with NERC BAL-003-1 will begin on December 1, 2016. Therefore the ISO will

need to implement any changes proposed in this initiative that require market software changes

by the ISO’s fall 2016 software release.

The ISO has several tariff provisions relating to frequency response. These tariff provisions

include

The ISO tariff section 4.5.6.1 states: “Participating Generators shall, in relation to each of

their Generating Units, meet all Applicable Reliability Criteria, including any standards

regarding governor response capabilities, use of power system stabilizers, voltage

control capabilities and hourly Energy delivery. Unless otherwise agreed by the ISO, a

Generating Unit must be capable of operating at capacity registered in the ISO

Controlled Grid interconnection data, and shall follow the voltage schedules issued by

the ISO from time to time.”

Appendix A to the ISO tariff defines Applicable Reliability Criteria to mean: “The

Reliability Standards and reliability criteria established by NERC and WECC and Local

Reliability Criteria, as amended from time to time, including any requirements of the

NRC.”

o Considerations for the ISO: These two tariff provisions refer to the WECC

standard on governor droop settings for synchronous generators; they do not

address non-synchronous generators.

Appendix K to the ISO tariff requires resources certified to provide spinning reserve to

respond immediately and automatically in proportion to frequency deviations through the

action of a governor or other control system in accordance with the minimum governor

performance requirements.14

o Considerations for the ISO: This addresses primary frequency response but

does not quantify amount of frequency response to address the new NERC

standard

The ISO will therefore need to develop procedures and associated tariff provisions to ensure

that sufficient frequency response capability is available in each operating hour to enable the

ISO to demonstrate compliance with the new obligation.

14 See ISO tariff Appendix K

http://www.caiso.com/Documents/AppendixK_AncillaryServiceRequirementsProtocolASRP_Jan1_2015.pdf



The ISO is analyzing 2013 and 2014 events to identify gaps within present capabilities in

meeting the frequency response obligation. This includes examining actual governor response

and breaking out this analysis by (1) generators providing spinning reserves, and (2) other

generators that are online.

In addition, the ISO is evaluating whether our current procurement of spinning reserves can

meet the new frequency response obligation. One consideration is that a generator may not be

capable of providing as much frequency response capacity as spinning reserve capacity.

Consequently, the ISO may have to modify spinning reserve procurement to ensure it obtains

an adequate quantity of frequency response. Another option could be for the ISO to develop a

separate market product to explicitly procure frequency response and ensure generator

headroom. However, the ISO likely cannot implement a separate frequency response product

by December 1, 2016. It would still have to implement another measure, such as using spinning

reserves, as an interim solution.

The ISO seeks stakeholder input on the following questions:

1. How should the ISO ensure there is sufficient frequency response capability on the

system in all hours to satisfy the new requirement?

2. Should the ISO develop a market product to procure frequency response?

3. If the ISO cannot develop a product in time for the fall 2016 release, what interim

solution would be appropriate? For example, using existing or modifying spinning

reserve procurement.

4. WECC standards apply only to synchronous generators. Should the ISO explore a

requirement that non-synchronous generators have primary frequency response

capability?



5. Initiative Schedule

Date Event

Fri 8/7/15 Issue paper posted

Thu 8/13/15 Stakeholder call

Thu 8/27/15 Stakeholder comments due

Mon 9/14/15 Straw proposal posted

Tue 9/22/15 Stakeholder meeting

Tue 10/06/15 Stakeholder comments due

Wed 10/30/15 Revised straw proposal posted

Early November Stakeholder call

Mid November Stakeholder comments due

Mid to Early December

Draft final proposal posted

Mid December Stakeholder call

Early January Stakeholder comments due

Wed 2/3/2016 Board of Governors meeting

Thu 2/4/2016

6. Next Steps

The ISO will discuss this issue paper with stakeholders on a conference call on August 13,

2015. Stakeholders should submit written comments by August 27, 2015 to

[email protected].

mailto:[email protected]