Preliminary Comments on Energy Storage Roadmap Process
CESA greatly appreciates the outreach currently being conducted by the CAISO,
supported by DNV GL, and Olivine as part of the Energy Storage Roadmap Stakeholder
Process. CESA’s members are responding directly to the survey that was distributed,
and CESA is also providing these preliminary comments to aid in organizing this early
stage of the Roadmap Process.
As the Roadmap Process team moves to the next phase of data compilation, CESA is
submitting these preliminary comments to provide additional detail and context from a
an energy storage industry perspective focused specifically on the use cases and barriers
called for by the standard survey instrument.
These preliminary comments provide a comprehensive overview of relevant use cases
and barriers related to energy storage in California. CESA respectfully submits these
preliminary comments for consideration as part of the Roadmap Process, and looks
forward to continuing to work with closely with the Roadmap team and all stakeholders
in this pioneering effort.
Use Case/Barrier Structuring
CESA has several comments related to the structuring of information in the stakeholder
outreach table. CESA understands that there must be a balance between clarity and
completeness, but would urge that the following issues be addressed in the early
drafting of the Roadmap.

There appears to be a lack of clarity around “Use Cases”, versus “Functions,” “Benefits,”
or “Services”. As part of the Energy Storage OIR, the Commission adopted SCE’s
definition of Use Case as “A collection of benefits that can be captured by a single
storage device sited in a particular place and used in a particular way”. We believe that
the table provided listed Functions/Services that might be provided, rather than Use
Cases. It could be helpful to clarify this.

The table appears to show bulk system functions only. We would add customer-sited
functions specifically:
o
Customer Bill Reduction through demand savings
o
Customer Bill Reduction through energy savings
o
Permanent Load Shifting
o
Customer Reliability
These functions often have very different barriers than the utility-side services listed, so
differentiation now could be helpful.

The table does not differentiate between connection locations (transmission connected,
distribution connected, and customer sited) that could be critical to parsing out which
and how barriers apply.

The table does not differentiate by resource owners or dispatch parties. Barriers and
rules will vary widely between systems that are rate based, IPP owned, 3rd party
financed, and customer owned, so ownership and dispatch would be worth addressing
at some point.

The table addresses combinations of functions in only a limited way. In our experience,
the combinations make for the greatest difficulty under our current rules.
CESA’s Proposed Energy Storage Use Case List
In an effort to provide a more complete list of use cases than currently provided in the
table, CESA has compiled the following additional table. We believe this represents the
most common use cases in California.
Standalone
Transmission
Sited
Generator Paired
Standalone
Distribution
Sited
Generator Paired
Rate Based (Trans Deferral & NERC Reliability)
Rate Based (Economic - Congestion Mgt, Avoiding lost cust. svc)
Rate Based (Policy - Renewables Integration – operational
integration (e.g., ramping) and RPS curtailment avoidance)
Dual Use (Partial Rate Based, Partial Market Participant)
Market Participant - Bulk Peaker (Energy, AS, & Resource
Adequacy capacity)
Market Participant - AS Only
VER 1 (wind/solar)
VER 2 (CSP molten salt)
Thermal + Turbine Inlet Chilling or CAES
Hybrid Thermal + Fast Response Storage
Thermal + Oxygen Chilling
Rate Based (Reliability - Dist Deferral, load mgt.)
Rate Based (Policy - enabling more cost effective DG, EVs)
Dual Use (Partial Rate Based, Partial Market Participant)
Market Participant - Bulk Peaker (Energy & AS)
Market Participant - AS Only
Community Energy Storage
Community Energy Storage + VER
VER 1 (wind/solar)
VER 2 (CSP molten salt)
Demand Side PLS
Bill Management
& Demand
Response
Bill Management
+ Market
Load-Paired / Participation
BTM
Utility Controlled
Reliability
EV Charging
Thermal + Turbine Inlet Chilling or CAES
Hybrid Thermal + Fast Response Storage
Thermal + Oxygen Chilling
Permanent Load Shifting - Electric
Business Customer, Building Thermal Mgt.
Business Customer, Peak/Max Demand Mgt.
Business Customer, Peak/Max Demand Mgt. + Solar
Residential Customer, TOU Bill Management
Residential Customer, TOU Bill Management + Solar
Aggregated C&I / VNM Solar + Storage
Multi-family Residential, Solar and Demand Mgt.
Business Customer, Bill + Market Participation
Business Customer, Bill + Market Participation + Solar
Residential Customer, Bill + Market Participation
Residential Customer, Bill + Market Participation + Solar
Grid Operation Benefits
Storage to provide reliability and aggregated market services
Storage to provide reliability and DR
EV Charging, Public Charging Station
EV Charging, Commercial or Municipal Fleet
EV Charging, Residential Home
Solar + Storage + EVs with bidirectional mkt participation
Storage + EVs with bidirectional mkt participation
EV Aggregated Charging with Market Participation (V1G)
EV Aggregated Charging/Discharging with Market Participation
(V2G)
CESA’s Initial Energy Storage Barriers List
FCESA has compiled a preliminary list of barriers that we see for energy storage. Many of these
are being addressed in current policy proceedings, but for the sake of completeness, we are
ilistinging them here.
Barriers included in Energy Storage Roadmap Survey are italicized.
1. Interconnection Barriers
1.1. Energy storage charging for wholesale market functions should be at wholesale rates.
Rule 21 and PTO load interconnection tariffs should be revised to clearly define what
functions of an energy storage resource constitute “load” versus what is not considered
end use load. Charging with the intent of storing power for resale should be excluded
from the definition of load because it is not an end use of power. On the other hand,
station power, such as heating and lighting, is an end use of power and such activities
should be considered “load.” This is a critical issue for the energy storage industry due
to the conflicting study processes and network upgrade cost allocation methodologies
between generation and load interconnection tariffs. Such a move is also consistent
with federal policy (FERC Order 792) and there is precedent with other states’ PUCs
(Texas) setting such a policy.
1.2. Charging Tariff Design. Standalone or generation-paired resources should be excluded
from the definition of end-use retail load, therefore removing any ambiguity with
respect to the CAISO’s intent to allow such resources to be eligible for wholesale
market participation for both charging and discharging.
1.2.1.Load-paired resources should have a dynamic pricing mechanism to enable
aligning end use demand shaping (& demand response activities) with local and
bulk system conditions, but should also be able to access wholesale market pricing
for charging specifically associated with any direct wholesale grid services they are
providing (i.e. not for the purpose of meeting end use load or for demand
response programs).
1.2.2.Recommendation: The Commission should direct the utilities to develop new tariff
structures for charging of distribution system-connected energy storage resources.
1.3. Implementation of D.14-05-033. The Commission should revise Rule 21 to make any
necessary changes required to conform to the direction provided in D.14-05-033 to
interconnection of energy storage paired with generation that is NEM-eligible, as well
as generation paired with energy storage that does not operate under Schedule NEM.
1.4. Non-Exporting Interconnection Agreements. Rule 21 should be revised to exempt
behind-the-meter energy storage resources that either only operate when the grid is
down or will never export energy to the grid from signing interconnection agreements.
1.5. Non-Exporting Interconnection Fees. The $800 interconnection application fee for
non-exporting energy storage should be cost-based at a considerably lower level and
capped.
1.6. Output Capacity Measurement. Where there is a single point of interconnection for
storage and generation, that point should be used to assess maximum output capacity
of the paired system, rather than separately counting individual generator and storage
capacities.
1.6.1.This issue, seeks to proactively address a potential future concern rather than
having to raise these issues after the fact. Utilities assess costs associated with
interconnecting storage and solar, which involves simply summing the inverter
capacities of the solar and the storage system to assess the distribution capacity
that is required to accommodate a project. However, in many cases, co-located
storage with renewable generation will only be used for ramping or smoothing, so
the storage output should not be added to the generator pMax. Implementation
may require a technical/algorithmic limit on the total system output.
1.7. Disconnection Requirements. Rule 21 should be revised to rationalize and standardize
disconnection requirements.
1.7.1.As an example, please see Attachment A for a configuration SCE is requiring of
SolarCity in their service territory. Disconnect B isunnecessary because of the UL
certified anti-islanding features of the solar inverter. Once disconnect A is tripped
the solar inverter also trips off, rendering disconnect B unnecessary.
1.7.2.Figure A: Disconnect Requirements in SCE Territory
1.7.3.Disconnect B is, in CESA’s view, unnecessary because of the UL certified antiislanding features of the solar inverter. Once disconnect A is tripped the solar
inverter also trips off, rendering disconnect B unnecessary.
1.8. Streamlining Rule 21/WDAT Transitions. The Commission should address streamlining
the interface between Rule 21 and PTO queue management processes. An applicant
should be able to transfer immediately from the Rule 21 distribution queue to the
WDAT transmission queue if study results indicate that is appropriate, without having
to wait for the next open window. Conversely, if study results indicate that it is
appropriate for an applicant to transfer to the Rule 21 queue from the WDAT queue it
should be able to do so immediately without waiting for the next acceptance window
to open.
1.9. Technical Screen Requirements.
1.9.1.Screen I, Options 3 & 4 and Screen J –These screens should be revised to allow for
larger systems without non-export relays in view of non-export relay costs and the
fact that operation under Schedule NEM eliminates any economic incentive to
export energy.
1.9.2.Screen B – This screen should be revised to make UL 1741 listing clearly sufficient
to meet all requirements, and that UL 1741 listing of individual generators is
sufficient, and It should also be clarified that a bank of generators does not need
to be UL Listed as such whether or not a group is separately packaged or further
enclosed within an additional chassis.
1.9.3.Screen I – This screen non-­­export path Option 3 should be revised to Increase the
rating threshold to 50% rather than the current 25% of the service equipment.
1.9.3.1.
The goal of this change is to harmonize the percentage of service
equipment rating with the percentage of service transformer capacity
rating. It is unclear why there is a more restrictive threshold on the
percentage the percentage of service equipment (25%) vs percentage of
service transformer capacity rating (50%).
1.9.3.2.
In the case of a 100 amp rated service equipment, a 25% limit would be
25 amps, which is equivalent to 6,000 watts at 240 VAC (25A x 240V =
6,000W). In cases where the customer is planning to use a battery inverter
to supply the entire house load at times, a 6,000 W inverter may be too
small.
1.9.4.Screen M – The 15% peak load limit of his screen should be raised for all
generation, whether or not it is paired with energy storage.
1.10.
Worst Case Study Assumptions & Upgrade Requirements. Energy storage
resource interconnections can be cost prohibitive when they are studied assuming
worst case charging/discharging. Studying worst case may actually run counter to the
point of installing energy storage devices, which are in many cases being built to
mitigate worst case impacts that are very unlikely to occur. For example, multi-hour
resources are unlikely to be charging when system loads and market prices are high.
Appropriate assumptions should be used to study the impacts of energy storage in the
interconnection process, and the proper dispatch and reliability software should be
used to manage impacts, rather than installing expensive new network upgrades to
manage worst case impacts.
1.11.
Cluster study opt-in for new tariff rules. Cluster 7 participants should have the
right to opt in to new study rules under development at the CAISO.
1.12.
Flexible deliverability interconnection study option. It would be helpful to
create a “flexible deliverability” study to assess ability to provide system flexible RA in
partial peak cases.
1.13.
Safe Harbor for Eenergy Storage Material Modification Approval when PMax
not changing. Adding storage to existing interconnection requests should not be
deemed material so long as the PMax does not change.
1.14.
Complex interconnection rules inhibiting adoption*
1.15.
Cost to meet interconnection rules inhibiting adoption*
1.16.
Cost and complexity of the WDAT specifically*
2. RA/Capacity
2.1. Deliverability Status is needed for resources providing only flexible capacity or flexible
capacity greater than standard capacity.
2.2. EFC should be unbundled from NQC.
2.3. The value of RA is uncertain in a variety of situations.
2.4. Deliverability calculations for Distributed/Aggregated resources are unclear.
3. Demand Response
3.1. Reduce Proxy Demand Response (“PDR”) participation size requirements. Reform
existing 100kW proxy demand resource minimum requirements to improve
participation. Bring the minimum requirement to 5kW (or as low as possible) to allow
many behind the meter resources, including those facilitated by energy storage, to
compete in the market.
3.2. Reduce Participation Duration Requirements.
3.3. Allow the Use of Least Cost Metering Solutions.
3.4. Allow DR to Compete with Generation in Wholesale Electricity Markets. Remove DR
participation barriers for energy, day-ahead scheduling reserve, capacity, synchronized
reserve and regulation.
3.5. Create Additional Dispatch Windows for Load Modifying and Supply Resource Demand
Response. Many IOU administered DR programs have a 1PM-7PM dispatch window,
which doesn't allow energy storage to plan for peak shaving.
3.6. Create Year Round DR Market Products.
3.7. Allow Supply Resource Demand Response to Capture Resource Adequacy Value. DR
resources need to be able to capture full RA value, including flexible capacity.
3.8. Continue to Provide Clarity in Updating Sub-LAPs and Assigning them to Pricing Nodes.
3.9. Remove Barriers for EV Participation in DR. Stationary energy storage coupled with EV
charging infrastructure cannot simultaneously participate in traditional utility DR
programs and provide services to the CAISO because DR participants are typically
prohibited by utility tariffs from participating in multiple DR programs at the same time.
3.10.
Properly Value Highly Dispatchable DR Resources. Establishing a value matrix
for slow, fast, short, and long duration resources to provide clarity for the
marketplace.
3.11.
Test market participation with charge and discharge capable energy storage
systems, capable of absorbing “excess supply” in different scenarios.
4. Metering & Telemetry
4.1. Increased expense of duplicative metering
4.2. Cost and complexity of required telemetry
4.3. Inability to track where/how storage is being charged preventing enabling tariffs from
being applied
4.4. Undetermined telemetry requirements for behind-the-meter frequency regulation
5. Behind the Meter (BTM) Wholesale Participation
5.1. A reconciliation method is needed for Retail/Wholesale uses
5.2. There is a lack of clarity around the BTM wholesale compatibility with retail programs
(eg NEM, etc.)
5.3. Supply/Demand Side DR program rules are not finalized for energy storage.
6. Ancillary Services
6.1. Lack of ability to access products from behind-the-meter points of connection
6.2. No enablers that allow operators to leverage unique characteristics of storage
(Regulation, Black Start, Spinning Reserve)
6.3. Not all benefits of storage can be monetized due to lack of product availability
7. Ratemaking Issues
7.1. Clarifying Wholesale Market Applicability for Charging (correlated with issues 1.1, 5.1,
5.2)
7.2. Retail Rate Design for Grid Responsive Resources
7.3. Retail Rate Incentives for Smart Charging & Discharging
7.4. Retail/TOU/Dynamic rates should reflect net peak
8. Standards
8.1. Lack of vetted standards in areas such as safety and reliability preventing storage from
being easily installed and deployed.
8.2. Lack of local codes / approval listings creating difficulty and time in commissioning
projects
9. Financial
9.1. Lack of long-term contracts for energy storage make financing projects difficult.
9.2. Lack of access to all revenue opportunities for storage preventing financing packages
being established for storage
9.3. Lack of electricity tariffs that allow all storage benefits to be monetized.
10. Market and Regulatory
10.1.
Under NGR Rules, energy storage resources cannot bit into multiple segments.
For instance, this prevents a storage resource from putting in a higher bid for a deep
discharge versus a shallow discharge.
10.2.
ISO treatment of storage assets as conventional generation in regards to
ancillary service certification quantities and maximum generation
10.3.
One LSE per PDR (and presumably per NGR due to procurement issues) prevents
widespread deployment
10.4.
class
Storage is not defined as an asset, either generation or transmission or unique
10.5.
Minimum size requirements to participate in market opportunities
11. Modeling
11.1.
No standard cost-effectiveness modelling tool available to the industry
11.2.
Hybrid applications of storage not accurately being modeled or benefits not
being fully accounted for
11.3.
Some storage technologies not accurately being modeled by ISO