COMMENTS OF THE ISO-RTO COUNCIL ON

NOTICE OF PROPOSED RULEMAKING REGARDING
ELECTRIC STORAGE RESOURCES AND

DISTRIBUTED ENERGY RESOURCE AGGREGATIONS
IN ORGANIZED WHOLESALE ELECTRIC MARKETS

Pursuant to the Federal Energy Regulatory Commission’s (the “Commission” or
“FERC”) Notice of Proposed Rulemaking issued on November 17, 2016,1 the ISO-RTO
Council (“IRC”)2 respectfully submits these comments in response to the Commission’s
proposal regarding electric storage resources and distributed energy resource (“DER”)
aggregations in the capacity, energy, and ancillary service markets operated by regional
transmission organizations (“RTO”) and independent system operators (“ISO”).3

1 Electric Storage Participation in Markets Operated by Regional Transmission Organizations and
Independent System Operators, Notice of Proposed Rulemaking, 157 FERC ¶ 61,121 (Nov. 17, 2016)
(“NOPR”).

2 The IRC comprises the Alberta Electric System Operator (“AESO”), California Independent System Operator Corp. (“CAISO”), Electric Reliability Council of Texas, Inc. (“ERCOT”), the Independent Electricity System Operator of Ontario, Inc. (“IESO”), ISO New England, Inc. (“ISO-NE”), Midcontinent Independent System Operator, Inc. (“MISO”), New York Independent System Operator, Inc. (“NYISO”), PJM Interconnection, L.L.C. (“PJM”), and Southwest Power Pool, Inc. (“SPP”). The AESO, IESO, and ERCOT are not subject to the Commission’s jurisdiction with respect to the matters addressed in this rulemaking and, therefore, do not join these comments.

3 NOPR at P 1.

I.INTRODUCTION

Members of IRC generally support the NOPR to remove barriers and better
accommodate electric storage resources and DER aggregations in the wholesale
electricity markets. These goals are a worthwhile endeavor. Allowing different types of
resources of varying size and capabilities to participate in wholesale electricity markets,
either directly or by aggregation, could create a more diverse, resilient, and competitive
electric market.

As the IRC is made up of RTOs and ISOs that will be required to implement the many provisions of the NOPR, the IRC proposes below certain key modifications and revisions to be included in the Final Rule. The IRC has long recognized the important balance between deference to stakeholder processes versus obtaining enough clear guidance from the regulator to ensure those processes are appropriately oriented, can prove successful, and—at the end of the day—receive regulatory approval. The IRC’s comments contained herein reflect that balance, including the need to respect regional processes and timelines, while still seeking overall Commission guidance in certain key areas that should be incorporated into the Final Rule.

II. JURISDICTIONAL CONSIDERATIONS

Jurisdiction is, by its nature, a fundamental legal issue that must be addressed as
ISOs and RTOs establish programs to integrate electric storage resources and DERs into
the wholesale markets. The IRC requests that FERC clarify where possible the boundary
between state (retail) and federal (wholesale) jurisdiction. Doing so will provide

necessary guidance to ISOs and RTOs as they develop the details of individual programs and help avoid conflicting approaches.

As part of this clarification, the IRC requests that FERC, working with the states,
address the jurisdictional issues surrounding injection and charging functions of certain
storage facilities. For example, one issue to be addressed is whether energy used to
charge a battery (including energy lost to the efficiency of the battery) and that is drawn
for the essential operation of the battery (such as the thermal regulation of the battery)
should be considered a sale for resale and, therefore, a wholesale transaction. For the
same reason, the Commission, working with the states, should clarify whether energy
drawn for consumption (such as traditional station power usage) is more appropriately
deemed not a sale for resale and, therefore, subject to a retail rate pursuant to state
jurisdiction.

Moreover, clear rules will need to be established in circumstances where the use
of the stored energy is unclear at the time of charging (e.g., an electric vehicle that may
use the electricity for fuel or sell the electricity back into the wholesale markets).
Outlining these jurisdictional lines early in coordination with the states can help parties
avoid the jurisdictional issues that have resulted in litigation in the past, as the industry
has witnessed with litigation over station power protocols for conventional generators.4

Additionally, the Commission should refrain from attempting, in the Final Rule,
to make generic determinations on whether particular net metering programs fall on one
side or the other side of the jurisdictional line. These are issues that must be examined in
the context of individual state programs with both federal and state regulators using their
respective authority in a coordinated manner to avoid double compensation based on the
details of the particular retail program. The IRC urges the Commission, working with the

4 Southern California Edison Co. v. FERC, 603 F.3d 996 (2010).

states, to address these threshold jurisdictional and rate issues and set forth clear processes for resolution among regulators. This approach will avoid forcing RTOs and ISOs, already challenged with implementation issues, to make decisions on legal jurisdictional issues under the Federal Power Act or rate issues that are grounded in individual state laws and regulations.

The Commission states that “to ensure that there is no duplication of

compensation, we propose that distributed energy resources that are participating in one
or more retail compensation programs such as net metering or another wholesale market
participation program will not be eligible to participate in the organized wholesale
electric markets as part of a distributed energy resource aggregation.”5 To the extent that
a DER is capable of, and seeks to, provide a retail service at times when it is not
providing a wholesale service, the Commission should permit multiple use applications.
The IRC believes that the legitimate concerns about double compensation can be
addressed under most conditions through metering and other real-time tools rather than
the imposition of inflexible rules requiring the resource to dedicate itself to one use
versus another; however, the IRC also recognizes the some of these scenarios may be
very complicated to differentiate between wholesale and retail activity.

By extension, in order to provide guidance to the marketplace and to assist in the
operation and administration of the final rule, the Commission should clarify that the
RTOs and ISOs are not responsible for determining in what retail transactions each DER
is engaged. Each RTO’s and ISO’s ability to prevent dual participation and double
compensation is limited by the information provided by the distribution utility, DER, and

5 NOPR at P 134.

metering. As a result, it would not be feasible to expect an RTO or ISO to determine, let
alone manage, a resource’s participation in one market versus another in real-time
operations.

III.PROPOSED RULES FOR ELECTRIC STORAGE RESOURCES AND

METERING ISSUES

A.State of Charge Issues

The IRC agrees with FERC’s proposal requiring information about a battery’s
State of Charge (“SOC”). The IRC concurs the SOC must be telemetered to the ISO or
RTO in real-time if required by telemetry rules that apply to other resources. The Final
Rule should clarify, however, that storage resource owner should manage the resource’s
SOC. Under some expansive readings, the NOPR could be interpreted as requiring RTOs
or ISOs to dispatch the electric storage resource hour-by-hour based on its specific SOC.
The ISO’s or RTOs’ responsibility in this area should be limited to following reasonable
operating parameters provided to it by the owner or aggregator of the electric storage
resource, but not necessarily managing the resource for that owner or aggregator.

B.Minimum Bid Parameters

The IRC agrees with FERC’s proposal to require that RTOs and ISOs incorporate
bidding parameters, to be provided by the resources’ owners, which account for the
physical and operational characteristics of electric storage resources. In addition, the IRC
agrees with the preliminary finding that the minimum parameters necessary for RTOs and
ISOs to effectively dispatch electric storage resources are the maximum energy charge
rate and maximum energy discharge rate. Those minimum parameters provide the ISOs
and RTOs with information about the physical and operational characteristics of electric
storage resources that establish their technical capability to provide the services they are

offering to provide. In some cases, however, the bidding parameters should be static and not subject to change through resource bids.

C.Metering Requirements

The IRC shares FERC’s interest in delineating the rules for wholesale market
transaction versus retail transactions. The IRC believes that metering arrangements and
accounting practices under most conditions can adequately track transactions to
determine whether they are wholesale or retail based on pre-defined criteria for making
this distinction, especially where the necessary retail metering infrastructure exists.
When a storage device or distributed energy resource that participates in the wholesale
markets is located behind the meter of a retail customer, special metering arrangements
and accounting practices are needed to separate wholesale from retail activities. But
retail metering infrastructure, which is subject to state jurisdiction, may be insufficient to
support the needed accounting practices to separate wholesale from retail activities. The
Commission should acknowledge that ISOs and RTOs have no jurisdiction to compel
state-regulated utilities to implement specific retail metering infrastructure.

The IRC also notes that wholesale metering rules for DERs must in all cases be
met. Metering hardware that meets retail metering requirements may not meet wholesale
requirements. For example, a lack of interval metering may be acceptable in certain
instances at the retail level but would frustrate the appropriate netting of power for
purposes of billing wholesale versus retail charges for resources that are participating in
the wholesale markets. For these reasons, wholesale and retail metering requirements
need to be harmonized so as to prevent impediments to the federal participation model or,
on the other hand, to avoid setting metering policy across the board in a manner that may

potentially put the Commission in the anomalous position of setting metering requirements for service that is predominantly retail in nature. This harmonization should recognize that the metering requirements and costs for participation in the wholesale market are voluntary in nature and therefore should be borne only by those DER providers who choose to participate in the wholesale market. In this way, DER owners would bear the metering costs they are causing while they benefit from the revenue streams available to them in the wholesale market.

IV.PROPOSED RULES FOR DER AGGREGATION

A.Relationship of DER Rules to Demand Response Rules

FERC has required that ISOs and RTOs establish rules for the participation of demand response in wholesale markets. The IRC requests that FERC clarify that the NOPR does not contemplate or imply any proposed changes to existing demand response rules, although ISOs and RTOs are free to propose revisions to their existing demand response rules to comply with the Final Rule.

B.Aggregation

The proposed rule requires ISOs and RTOs to allow the participation of
aggregated storage and DERs, which consist of multiple resources within a specified
regional or electrical distance. The amount of megawatts to meet an individual minimum
and maximum resource capacity requirement should not be mandated by FERC, but
instead left to the requirements of the individual RTO or ISO that is managing congestion
on its system.

C.Locational Limitations on Aggregation

FERC proposes to require ISOs and RTOs “to establish locational requirements
for DERs to participate in a DER aggregation that are as geographically broad as
technically feasible.”6 This requirement strikes the appropriate balance between stating
an important market principle for the accommodation of smaller DERs, and providing the
necessary flexibility to ISOs and RTOs to implement feasible solutions given the physical
and business constraints that are particular to each. The IRC supports allowing each ISO
and RTO to establish reasonable, nondiscriminatory locational limitations that take into
account disparate impacts of injections given its market design and the particular location
and size of each of the aggregated resources. The IRC specifically suggests that the
Commission not impose a requirement that ISOs and RTOs must accommodate an
individual DER aggregation at more than one pricing node or interconnection point (or
spanning multiple distribution utilities). In the NOPR, the Commission recognizes
important reasons that RTOs and ISOs may limit aggregations to a single node or
interconnection point, such as concerns about transmission constraints and price
formation.7 The IRC urges the Commission to carry this provision forward to the Final
Rule by allowing each RTO and ISO to determine how best to apply geographic
limitations on aggregation. Of course, these limitations can be reviewed in the future
once further experience is gained with DER aggregations, but represent an appropriate
starting point as RTOs and ISOs wrestle with the growth of behind the meter aggregated
resources coming onto the grid and charging and discharging at an ever growing pace.

6 Id. at P 139.

7 See NOPR at P 138.

D.Coordination with Distribution Utilities

The IRC supports coordination and communication between the ISOs and RTOs and the distribution utilities to review all resources in the DER aggregation portfolio to ensure safe and reliable interconnection and dispatch. This coordination could include an upfront review of resource specifications and requirements and how the resource operates individually and as part of an aggregated set of resources, and also could include the sharing of information on day-ahead schedules, real-time dispatch, and real-time constraints on the distribution system.

In establishing requirements, FERC should be mindful that distribution systems
have a diversity of physical configurations, regulatory frameworks, and existing
operational processes and infrastructure. Distribution utilities may or may not have
distribution management systems that can assess the impact of DER dispatch on
distribution system reliability, safety, and power quality, which may require restricting
DER dispatch to protect the system. Such differences in system capabilities may require
different types of coordination processes. FERC requirements in this regard should
therefore be at a high-level only, in the domain of general principles, rather than specific
details.8

The IRC requests the Commission to provide, as part of any Final Rule, more
guidance as to the role of the Electric Distribution Company (“EDC”) in reviewing
interconnection and coordination requests, and specific direction as to where and how
disputes are to be resolved. The ISOs and RTOs should not be put in the middle of
disputes between DER or energy storage resources and EDCs over whether or not to

8 See NOPR at PP 153-155.

accept a given interconnection, the impact of a given DER on the distribution grid, or both. Rather than simply requiring “coordination,” FERC should clearly define the respective roles of the ISOs and RTOs versus the EDCs, and include a framework for dispute resolution (including specification of who has authority to resolve such disputes as between the Commission and the states) to prevent unnecessary litigation. Finally, distribution interconnection studies should generally remain the responsibility of the distribution utility and not become the province of the RTOs and ISOs.

E.Metering, Telemetry, and Settlements

The IRC is supportive of defined metering and accounting practices for DER
aggregations, which should be noted in accordance with each ISO’s or RTO’s tariff and
other applicable governing documents as appropriate. Each ISO and RTO should be
given the flexibility to determine where this information is defined, instead of uniformly
requiring them to be defined in each ISO’s and RTO’s tariff. FERC should not be overly
prescriptive with metering and telemetry requirements and should let each ISO and RTO
develop reasonable and nondiscriminatory metering and telemetry requirements
consistent with the requirements on generation of comparable size and location on the
grid.

The IRC supports tariff revisions to require DER aggregators to retain individual
resource performance aggregated settlement data for ISO and RTO settlement and audit
purposes. To the extent that the NOPR is effectively creating a “right” of DERs to buy
and sell power at wholesale, the Final Rule should specify the right of ISOs and RTOs to
require metering and telemetry of similar quality to generation of a comparable size to
avoid later disputes and problems with, inconsistent industry roll-out across the nation.

F.Proposed Implementation Deadlines

The IRC believes that the suggested deadline to develop and implement the proposed reforms within twelve months of the date of the ISOs’ and RTOs’ compliance filings is overly aggressive given the broad and far reaching scope of this NOPR, and the complexity and impacts of electric storage resources and DER aggregations, especially as applied to behind the meter distributed energy resources participating in the wholesale market other than as demand response. The implementation and the integration of DER aggregations will require extensive market rule revisions in the ISOs’ and RTOs’ tariff and manuals, internal procedures and software changes, which cannot feasibly be completed within a twelve-month period.

Additionally, each ISO and RTO is in varying stages of development and
deployment of storage and DER resources. These efforts require significant time to
complete technical feasibility assessments to successfully support changes and
enhancements to the RTOs’ and ISOs’ respective market systems. Further, the
capabilities of distribution utilities to assess the impact of DER dispatch on distribution
system reliability, safety, and power quality vary widely throughout the country. For
many distribution utilities, it will take some time to develop these capabilities. The IRC
requests the FERC allow each ISO or RTO enough time and flexibility for the design,
stakeholder discussion, and implementation of the proposed reforms.

The IRC recommends that, to provide some specificity and order to the process,
the Final Rule should require that within 180 days from its promulgation, each ISO and
RTO vet with its stakeholders and file with the Commission a proposed implementation
plan and schedule—-not necessarily limited to a twelve-month period, and explanation

thereof, which would then be the subject of notice and comment. Each RTO and ISO
would be required to justify its particular proposed timelines and work plans.
This kind of transparent but flexible compliance process, which each RTO and ISO can tailor for its own context in consultation with its stakeholders, is preferable to a single compliance date given the multitude of issues, competing priorities and differing levels of work undertaken to date on these issues within each RTO and ISO across the country.

V.CONCLUSION

The IRC stands ready to work with all stakeholders to support the broader goals
of integrating DERs and energy storage resources into ISO and RTO markets. The IRC
respectfully requests that the Commission consider these comments in response to the
NOPR.

Respectfully submitted,

/s/ Margoth R. Caley/s/ James M. Burlew

Raymond W. HepperCraig Glazer

Vice President, General Counsel, and SecretaryVice President-Federal Government Policy

Theodore J. ParadiseJames M. Burlew

Assistant General Counsel, Operations andSenior Counsel

PlanningPJM Interconnection, L.L.C.

Margoth R. Caley2750 Monroe Boulevard

Senior Regulatory CounselAudubon, Pennsylvania 19403

ISO New England Inc.james.burlew@pjm.com

One Sullivan Road

Holyoke, Massachusetts 01040

mcaley@iso-ne.com

/s/ Anna McKenna/s/ Gregory J. Campbell

Roger E. Collanton, General CounselRobert E. Fernandez, General Counsel

Anna McKennaRaymond Stalter

Assistant General Counsel, RegulatoryDirector of Regulatory Affairs

Andrew Ulmer Director, Federal RegulatoryGregory J. Campbell

AffairsAttorney

California Independent System OperatorNew York Independent System Operator,

CorporationInc.

250 Outcropping Way10 Krey Boulevard

Folsom, California 95630Rensselaer, NY 12144

amckenna@caiso.comgcampbell@nyiso.com

/s/ Andre Porter/s/ Paul Suskie

Andre PorterPaul Suskie

Vice President and General CounselExecutive Vice President & General Counsel

Midcontinent Independent SystemChristopher M. Nolen

Operator, Inc.Attorney

720 City Center DriveSouthwest Power Pool, Inc.

Carmel, Indiana 46032201 Worthen Drive

aporter@misoenergy.orgLittle Rock, Arkansas 72223-4936

psuskie@spp.org

February 13, 2017

CERTIFICATE OF SERVICE

I hereby certify that I have this day served the foregoing document upon each person designated on the official service list compiled by the Secretary in this proceeding.

Dated at Norristown, PA, this 13th day of February, 2017.

James M. Burlew

Senior Counsel

PJM Interconnection, L.L.C.
2750 Monroe Boulevard
Audubon, PA 19403
(610) 666-4345