UNITED STATES OF AMERICA
BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

Mandatory Reliability Standards for the Bulk)Docket Nos. RM06-16-010

Power System)RM06-16-011

COMMENTS OF THE ISO/RTO COUNCIL

The ISO/RTO Council (“IRC”)1 respectfully submits these joint comments in response to
the September 24, 2010 Notice Allowing Post-Technical Conference Comments of the Federal
Energy Regulatory Commission (“Commission”) with respect to the September 23, 2010
Technical Conference concerning Frequency Response in the Wholesale Electric Grid.

I.COMMENTS

A. Introduction

The IRC submits that Frequency Response must be addressed in a comprehensive

manner that includes the following issues: (1) Interconnection impacts, (2) defining the roles and responsibilities of Balancing Authorities (“BAs”), i.e., control, and (3) the supply resources that actually have the frequency response capability and provide the response.

1 The IRC is comprised of the Alberta Electric System Operator (“AESO”), the California Independent System

Operator (“CAISO”), Electric Reliability Council of Texas, Inc. (“ERCOT”), the Independent Electricity System

Operator of Ontario, Inc., (“IESO”), ISO New England Inc. (“ISONE”), Midwest Independent Transmission System Operator, Inc. (“Midwest ISO”), New York Independent System Operator, Inc. (“NYISO”), PJM Interconnection,
L.L.C. (“PJM”), Southwest Power Pool, Inc. (“SPP”), and New Brunswick System Operator (“NBSO”). The IESO, AESO and NBSO are not subject to the Commission’s jurisdiction, and these comments do not constitute
agreement or acknowledgment that such entities can be subject to the Commission’s jurisdiction. AESO and NBSO have not joined in these comments. The IRC’s mission is to work collaboratively, to develop effective processes,
tools and standard methods for improving the competitive electricity markets across North America. In fulfilling
this mission, it is the IRC’s goal to provide a perspective that balances reliability standards with market practices so that each complement the other, thereby resulting in efficient, robust markets that provide competitive and reliable
service to customers. Additionally, individual IRC members may file separate comments in this proceeding.
Accordingly, the absence of the IRC’s comments on specific proposals in these comments should not be deemed
acquiescence on the part of the IRC members to such proposals.

The standard for Frequency Response that existed prior to today’s mandatory Reliability
Standards framework was predicated on vertically integrated control areas that controlled and, in
most cases. owned the supply assets. That standard was based on individual control area
requirements related to controling Area Control Error, not on the Interconnection’s frequency
response needs.

The bulk power system has changed significantly since then. While some regions of the
U.S still operate under vertically integrated utility constructs, a large percentage operate under
organized markets. Even in the areas with vertically integrated utilities, there is competition for
supply. Added to this, there is a mandatory reliability standards construct that applies
universally. Under the current NERC construct, control areas have been effectively restructured
into a variety of Functional Entities that serve different roles and have different obligations.

The Commission must examine frequency response issues in this new context and
consider the three primary issues related to frequency response identified above. Given the
fundamental changes in the industry, the IRC supports the concept of developing an
Interconnection Frequency Response (“IFR”) to address frequency response. This obligation,
however, should not be based on measured response, but rather on predefined Interconnection
primary control needs. Those needs could be defined either in terms of a predefined real time
frequency response, or in terms of a predefined amount of governor response capacity. No longer
can one assume that control areas will/can build the necessary response characteristics for the
assets within their footprint. From an operational perspective an IFR could take into account the
reliability needs of each individual Interconnection, thereby ensuring a given margin of
reliability. From an operational and market perspective, such an approach would allow
2

Vertically-Integrated Utilities (“VIUs”), BAs and organized market operators to design

frequency response related services to take into account the specific needs and circumstances of
both the Interconnection and the operating area. This could increase the aggregate
Interconnection response while reducing individual BA obligations (just as power pools were
able to increase operating reserves for the pool while reducing the individual utilities need to
carry reserves). Whether or not a Reliability Standard must be written to assign that obligation
to the ERO is a matter for the Commission to decide. The IRC proposes that such an
Interconnection obligation be developed through an ERO-coordinated technical team.
The IRC agrees with the Commission’s direction of having unambiguous measureable objectives and definitions for standards and believes that the approach it proposes in these
comments is consistent with this goal. The IRC supports identifying a clear IFR objective be it a
frequency-based objective or a contingency magnitude based objective. By defining a clear
objective both the Commission and the ERO can objectively assess the adequacy of existing
levels of frequency response, and this information will facilitate the goal of ensuring that
frequency response promotes system reliability, because it will provide for ongoing expected
levels of response. This approach will also ensure that technical parameters and underlying
issues relevant to frequency response are considered, which will in turn, support the maintenance
of future frequency response at levels equal to or greater than existing levels.

B. The Commission And NERC Must Re-Think The Concept Of Obligating BAs to
Provide Frequency Response

An important issue that needs to be re-visited is the issue of who should be obligated to provide frequency response. The IRC believes that once an objective IFR obligation is defined by the ERO, then that objective should be allocated to the providers of that response.

Traditionally, the providers were the control areas (now known as BAs) because the control
areas had power over the resources under their jurisdiction. In today’s environment however
BAs do not have that control. The IRC believes that in the current environment, where a
growing number of supply resources do not have governor controls and many others are
restricted from providing primary response, the Industry must not casually accept the concept of
obligating BAs to provide frequency response. The IRC offers the extreme case where no units
have any governors. Obligating the BAs would have no impact on the provision of frequency
response. The BAs neither design the units, nor do they themselves create such a response. In
the less extreme but more probable case where suppliers do not maintain their governors, the
BAs are similarly impaired from complying with a frequency response obligation. The IRC
points out that the role of the BA is not to create frequency response. Rather the role of the BA is
to ensure that the frequency response that is provided by the primary control action of its supply
resources is adequate to arrest frequency decline and stabilize the system following a disturbance
or to react to changes in Interconnection frequency during normal operation. This BA role
requires coordinating (a) the primary response production with (b) the BA’s own control
obligation with (c) the needs of sharing in both short-term (primary control) frequency needs and
with (d) longer term (secondary control) frequency needs. This coordination has been and
continues to be done through the frequency bias setting used in the BAs Area Control Error
(“ACE”) calculation. The BAs must, of course, include a frequency bias setting in their ACE
equations. The bias setting ensures that the primary response provided by the governors is not
counteracted by secondary (regulation) controls. Requirements in the current BAL-003 would
still be useful.

Moreover, today thermal units (and hydro resources in some regions) provide most of the
frequency response. However, as the thermal units are decommissioned and replaced by
renewable assets, the power system will have an equivalent amount of supply capacity but may
have less primary response unless these new resources install the necessary facilities and have
the capability to actively supply their share of the IFR. While thermal (and hydro) generators
have historically been the primary source of Frequency Response, the focus of the allocation of
IFR should not be limited to generators, but should recognize demand-side resources, as well as
storage batteries and flywheels. To the extent these demand-side and storage service providers
can and do provide primary response to changes in frequency, those providers should be properly
accounted for in any frequency response objective. A global generator-centric standard, as
suggested by the Commission, would be one such idea, but the IRC must raise the concern that
such an approach is counter to many of the state-mandated renewable portfolio mandates that
require installation of resources that do not necessarily have governors.. The key point is that it
is not reasonable to place the BAs in the middle of the obligation. Any primary control standard
must be based on the capabilities of the Functional Entities that the standard applies to.

C. The Issue Of Establishing An Appropriate Frequency Bias Setting Should Be
Addressed

Further, it is worth highlighting that a major objective of a one percent of peak load as a
minimum Frequency Bias Setting was to ensure that “secondary response” could be produced
whenever there was a call for “primary response” and was not meant as a one percent primary
response2. The Industry recognized that any shortfall in primary response (i.e., between what the
setting calls for and what the resources provide) will show up as a change in ACE and thus be

2 BAL-003-0.1b Requirement 5 obligates a Balancing Authority to set its Frequency Bias Setting to at least 1% of its estimated yearly peak demand to ensure that the Automatic Generation Control does not withdraw generation
following the governor response of generating units.

handled by the secondary controls (e.g., automatic generation control (“AGC”)). Ensuring that a setting is greater than the response ensures that additional energy will be forthcoming from
AGC to further support the Interconnection frequency. The idea that the frequency bias setting would equal the natural frequency response at all times is an idealized state, and to make the
setting close to the expected response would risk backing off resources in those instances when the response is greater than the bias setting. The IRC supports the current standard concept of overbiasing the system, but questions whether the one percent level is the proper amount or
whether it is even the only way to address the concern.

D. A Frequency Response Standard Based On A Capacity Obligation Appears
Preferable To One Based On An Energy Obligation

Likewise, there is a need to examine whether a true frequency response standard should be a capacity obligation or an energy obligation. Capacity obligations are easier to enforce than
energy obligations. It is easier and clearer to check that a resource has a governor and can
respond automatically and proportionally to frequency changes outside a set bandwidth than it is to determine if the device is used. It is more difficult to properly evaluate the energy produced
for any given event, given that the resource may be in a mechanical transition phase (valves
opening or closing) or responding to AGC (thus moving as fast as possible and not
distinguishable between primary and secondary responses). Pre-operational qualifications and
tests can work as a surrogate energy measure, recognizing that the system needs to rely on
average responses, not individual responses.

E. A Number Of Factors Should Be Taken Into Consideration In Connection With
Any Primary Control Response Obligation

One last complication is the fact that a provider’s frequency response as measured for a
given event is not a linear function. Provider response changes as a function of demand and
6

system conditions. Fully loaded generators provide less response than partially loaded

generators. Ramping generators provide no measureable response. The Interconnection needs also vary by season and time of day. The IFR during minimum load conditions is significantly different than the IFR during maximum load conditions. All of these factors must be considered in connection with establishing a primary control response obligation.

In light of the above, the IRC respectfully suggests the following Implementation Plan:

1. The Commission order that the BAL-003 as it relates to the frequency bias setting
requirements be revised to focus on the minimum frequency bias setting and to
eliminate the current explanatory text note included in BAL-003. Because this
fundamental technical content will not change, the new BAL-003 can be updated
quickly.

2. The Commission indicate its preference for a frequency-based or a contingency
based Interconnection objective, and assign the ERO to use the data that it
currently has to create the basis for an IRF SAR. The IRC suggests that this
research work initially be done independent of the Standards Development
Process but that a SAR be proposed by no later than the third quarter of 2011.

II.CONCLUSION

In summary, the IRC reiterates the following important points for the Commission to take

into account the following in making any decisions in this proceeding:

The Interconnections have sufficient Frequency Response at this time.

The focus of BAL-003 should be to properly define the roles and obligations for:

 Interconnection Frequency objective  BA setting in ACE

 Construction of Primary Control Service providers

 Response obligations of those Primary Control Service providers

Similar to the Control Performance Standard (BAL-001-0.1a R1), BAL-003

should be “tunable” such that the Interconnection target response can be adjusted as the industry evolves.

 The BAL-003 standard should lay the groundwork for informed decisions and be

“tunable” such that performance targets change as risk changes.

WHEREFORE, the IRC respectfully requests the Commission to take into consideration the above comments.

Respectfully submitted,

/s/ Craig A. Glazer

Craig A. Glazer

Vice President - Federal Government Policy Rob Eckenrod

Counsel

PJM Interconnection, L.L.C.

1200 G Street, N.W., Suite 600 Washington, D.C. 2005

/s/ Stephen G. Kozey

Stephen G. Kozey

Vice President, General Counsel and Secretary

Midwest Independent Transmission System Operator, Inc.

P.O. Box 4202

Carmel, Indiana 46082-4202

/s/ Robert E. Fernandez

Robert E. Fernandez

Vice President and General Counsel Elaine Robinson

Director of Regulatory Affairs

New York Independent System Operator,
Inc.

10 Krey Boulevard

Rensselaer, New York 12144

/s/ Raymond W. Hepper

Raymond W. Hepper

Vice President, General Counsel, and Secretary Theodore J. Paradise

Senior Regulatory Counsel

ISO New England Inc.

One Sullivan Road

Holyoke, Massachusetts 01040

/s/ Anthony Ivancovich

Anthony Ivancovich

Assistant General Counsel - Regulatory

California Independent System Operator Corporation

151 Blue Ravine Road
Folsom, California 95630

/s/ Stacy Duckett

Stacy Duckett

General Counsel and Corporate Secretary

Southwest Power Pool, Inc.

415 North McKinley #140 Plaza West

Little Rock, Arkansas 72205

/s/Brian Rivard

Brian Rivard

Manager, Regulatory Affairs
and Senior Policy Analysis

Ontario’s Independent Electricity
System Operator

655 Bay Street, Suite 410 Toronto, Ontario

M5G 2K4

Dated: October 14, 2010

s/ Matthew Morais

Matthew Morais

Assistant General Counsel

Electric Reliability Council of Texas

7620 Metro Center Drive Austin, Texas 78744

CERTIFICATE OF SERVICE

I hereby certify that I have served the foregoing document upon all of the parties listed on the official service list for the captioned proceedings, in accordance with the requirements of Rule 2010 of the Commission’s Rules of Practice and Procedure (18 C.F.R. § 385.2010).

Dated at Folsom, California this 14th day of October, 2010.

Anna Pascuzzo