the study of energy storage in ontario distribution systems study of energy storage... · the study...

The Study of Energy Storage in

Ontario Distribution Systems

May 2017

Energy storage technologies have the potential to provide a number of benefits to Ontario’s

electricity distribution system. This report seeks to identify and quantify the benefits, costs,

opportunities, and barriers of various energy storage applications on Ontario’s distribution

system.

Prepared by:

The Study of Energy Storage in Ontario Distribution Systems

Table of Contents_

Executive Summary ............................................................................................................................................... i

Energy Storage Already Exists in Ontario ...................................................................................................... i

Benefits of Energy Storage................................................................................................................................. i

Barriers to Energy Storage ................................................................................................................................. i

Use Cases and Conclusions .............................................................................................................................. ii

Background and History of Energy Storage in Ontario ................................................................................... 1

Stakeholder Identification and Outreach ........................................................................................................... 3

Current State of Distribution Connected Storage in Ontario .......................................................................... 4

Deployed Technologies .................................................................................................................................... 4

Current and Planned Projects .......................................................................................................................... 5

Revenue Streams Available to Project Owners ............................................................................................. 9

Barriers to Current Projects ............................................................................................................................ 13

Ontario Distribution Connected Storage Benefit Assessment ...................................................................... 14

Location ............................................................................................................................................................. 14

Distribution Grid Topology ........................................................................................................................... 14

Size of Distributor ............................................................................................................................................ 15

Geographic Environment ............................................................................................................................... 15

Possible Benefits ............................................................................................................................................... 16

Monetary Value of Benefits ............................................................................................................................ 16

Beneficiaries of Energy Storage ..................................................................................................................... 16

Ontario Distribution Connected Storage Barrier Assessment ....................................................................... 17

IESO and LDC Connection and Communication Costs ............................................................................. 17

Permits and Licensing ..................................................................................................................................... 17

GA and Demand Charges .............................................................................................................................. 17

Other Commercial Issues ............................................................................................................................... 20

Other Non-Commercial Issues ...................................................................................................................... 21

Example Use Cases .............................................................................................................................................. 23

Conclusions .......................................................................................................................................................... 40


Suggestions on How to Monetize Indirect Benefits .................................................................................... 40

Tools Available to Address Identified Barriers ........................................................................................... 42

Top Three Scenarios ........................................................................................................................................ 43

Appendix A .......................................................................................................................................................... 45

Appendix B ........................................................................................................................................................... 49

Appendix C .......................................................................................................................................................... 56

Appendix D .......................................................................................................................................................... 58

Appendix E ........................................................................................................................................................... 64

References ............................................................................................................................................................. 70


Table of Figures

Figure 1: Example Use Case 15 Year Lifecycle ............................................................................................ 24

Figure 2: Present Value of Benefits and Costs - Case 1 .............................................................................. 26




Figure 6: Present Value of Benefits and Costs - Case 5 with Demand Charges ..................................... 38

Figure 7: Present Value of Benefits and Costs - Case 5 without Demand Charges ................................ 39

Figure 8: Distribution of Non-Spinning Operating Reserve Market Price .............................................. 51

Figure 9: Distribution of Spinning Operating Reserve Market Price ....................................................... 51

Figure 10: Distribution of HOEP Market Price .............................................................................................. 52

Figure 11: Case 1 – 15 Year Project Life Cost and Benefit Chart ................................................................. 58




Figure 15: Case 5 (Demand Included) – 15 Year Project Life Cost and Benefit Chart ............................. 62

Figure 16: Case 5 (Demand Not Included) – 15 Year Project Life Cost and Benefit Chart ...................... 63

Figure 17: Generation Cash Flow .................................................................................................................... 64

Figure 18: Storage Process Cash Flow ............................................................................................................ 65

Figure 19: Imbalance of HOEP and GA Payments ....................................................................................... 67

Figure 20: Case 1 – Original Scenario and 20% GA Scenario ...................................................................... 68





Table of Tables

Table 1: Ontario Energy Storage Project Summary..................................................................................... 8

Table 2: Currently Monetizable Benefits, from Appendix A, Value Matrix .......................................... 10

Table 3: Benefit Definitions, from Appendix A, Value Matrix ................................................................ 11

Table 4: Direct Benefit Matrix ...................................................................................................................... 12

Table 5: General Barriers to Energy Storage Matrix ................................................................................. 13

Table 6: Demand Charge Calculation (1 MW, 4MWh, operating daily) ................................................ 18

Table 7: Usage Charge Calculation (1 MW, 4 MWh, operating daily) ................................................... 18

Table 8: Global Adjustment Calculation ..................................................................................................... 19

Table 9: Benefit Streams - Case 1 ................................................................................................................. 25

Table 10: Monthly Common Costs - Case 1 ................................................................................................. 25

Table 11: One Time Common Costs - Case 1 ............................................................................................... 26


Table 13: Common Costs – Case 2 ................................................................................................................. 28



Table 16: Common Costs - Case 3.................................................................................................................. 31








Table 24: Indirect Benefit Value Matrix ........................................................................................................ 41

Table 25: Five Coincident Ontario Peaks for 2015 ....................................................................................... 53

Table 26: Permit Type and Possible Cost...................................................................................................... 57


i

Executive Summary

Engagement

In March 2016, the Ministry of Energy requested a Study of Energy Storage in Ontario Distribution

Systems. This study seeks to identify and assess opportunities for beneficial energy storage

applications within Ontario’s distribution system. In doing so, regulatory, technical, commercial, and

non-commercial barriers that may prevent this value from being realized by utilities, rate payers, and

owners are also examined.

Energy Storage Already Exists in Ontario

Energy storage has existed in Ontario for many years. The most developed technology is pumped

hydro storage, using an elevated water reservoir to drive turbines. Other technologies, such as

batteries, flywheels, and compressed air, have made several technological advancements and continue

to mature. These advancements are making other technologies more viable options for distribution

connected energy storage projects. In recent years, many projects varying from small behind-the-meter

batteries to large regulating facilities located near transformer stations have been commissioned.

Ontario is investigating what can be done to further enable the benefits provided by distribution

connected energy storage projects in the province.

Benefits of Energy Storage

There are many direct and indirect benefits stemming from energy storage installations. Direct

benefits of storage include: improved asset and generation management, regulation services, operating

reserve, and system reliability improvement. These benefits are innate for storage projects, and many

of the benefits are better achieved at the beginning and middle of a feeder rather than the end of a

feeder. Indirect benefits of energy storage include: excess generation mitigation, greenhouse gas

reduction, and the enablement of higher penetrations of renewables. A significant challenge that has

emerged for energy storage projects is the inability of storage facility owners to monetize these indirect

benefits in order to enable projects to be considered economically viable.

Barriers to Energy Storage

Many barriers to energy storage are caused by projects fitting into both “generation” and “load”

categories within a distribution system simultaneously. Current Ontario regulation, market rules, and

industry thought processes are geared to a more binary distribution system and storage generally does

not fit this model. As a result, for many storage applications Ontario’s Global Adjustment (“GA”)

charges, utility demand charges, and other similar tariffs are real costs that apply when a facility is

storing energy but cannot be recouped through existing market mechanisms while discharging. The


ii

cost of GA alone can amount to more than all other common project costs combined, and may eclipse

the amount of revenue that is available to a given project for the direct benefits it provides.

Use Cases and Conclusions

Included in this report are five energy storage “use cases” intended to demonstrate the versatility

as well as the impact of benefit streams, location, and barriers for typical applications. Each use case

demonstrates a different benefit stack, common project costs (independent of technology), and

potential revenue streams if all benefits could be monetized. The use cases clearly demonstrate the

magnitude of Global Adjustment charges compared to other costs. They also identify other potential

benefits provided by energy storage facilities that would require regulatory/market rule changes

and/or Power Purchase Agreements (“PPA”) in order to monetize these benefits. These are termed

“indirect benefits”.

This report presents several conclusions that are of significance to the reader. The first of these is

that technically, more benefits can be provided by distribution connected storage located near

transmission stations as opposed to further away. This may seem intuitive to informed readers,

however less intuitive and somewhat unexpected is the conclusion that, commercially, more benefits

can be monetized when furthest away from the transformer station (particularly behind the meter),

given Ontario’s market structure. Without intervention, it appears that behind the meter applications

will outpace the growth of all other applications. The reader is provided with two key tools, the Benefit

Matrix and Value Matrix, which can be used to assess other potential use cases in Ontario beyond the

five cases illustrated in this report.

Several suggestions are provided for consideration to facilitate energy storage project development

in Ontario. Global Adjustment settlements based on net consumption of the storage facility, reduced

demand charges based on the benefits provided, consideration of PPAs as a means to enable storage

owners to monetize indirect benefits, and integration with renewable generators are among the

suggestions provided.


1

Background and History of Energy Storage in Ontario

An essential characteristic of energy storage

systems is their ability to shift energy from one

period of time to another. When applied

efficiently, this unique ability often increases

the value of energy when it is consumed as

compared to if it had been consumed at the

point in time when it was generated. As a

result, energy storage systems have the

capability to provide several services and

advantages to an electrical distribution system.

Generally, these services can include:

Shifting energy consumption from high

demand periods to lower demand

periods

More efficient utilization and

management of excess generation

Capacity and congestion management

Ancillary services

Deferral of investments in, or expansion

of, distribution systems

Providing operating reserves

Providing redundant power in the event

of an outage

Firming the output of variable generation

resources (i.e. solar, wind, run of the

river)

Due to the variety of potential services

provided, benefits afforded by energy storage

systems can vary greatly. The type of storage

technology in question, the specific needs of the

electrical grid, the capacity of the energy

storage system, the physical size of the energy

storage system, the location of the system (both

geographically and electrically), and other

factors could significantly impact the benefits

delivered by energy storage facilities.

Recognizing these benefits, several

jurisdictions have acted to implement energy

storage projects. In California, Southern

California Edison Utility announced plans to

commission 261 MW of energy storage capacity

in 2014, as part of an initiative to offset the

closing of a 2,200 MW nuclear plant. In New

York, Con Edison was strategizing to use

energy storage resources to avoid or defer the

construction of an estimated $1 billion

substation. Texas, which has the most installed

wind capacity among all 50 states in 2016, used

energy storage to smooth the inherently

intermittent output of wind generators [1].

Despite a recent surge of interest, energy

storage is not a new phenomenon in Ontario.

The 174 MW Sir Adam Beck Pump Generating

Station and its 300 hectare reservoir have been

providing energy storage benefits to Ontario’s

electricity grid since 1958. Since that time,

existing technologies are improving, new

technologies are emerging, and the Ontario

electricity distribution system is evolving. A

number of energy storage projects have

recently developed in Ontario, utilizing various

technologies, with more projects planning to

come online in the coming months and years.

In 2012, Ontario’s Independent Electricity

System Operator (“IESO”) launched the

Alternative Technologies for Regulation (ATR)


2

procurement to secure 10 MW of regulation

service. While not specifically targeted in this

procurement, energy storage systems were

featured prominently among the potential

service providers. The IESO subsequently

signed contracts with flywheel and battery

storage providers. These projects have been

built and commissioned, and are currently

providing regulation services to the IESO as of

2016.

The IESO issued its Grid Energy Storage

procurement with the objective of specifically

investigating energy storage system capabilities

for providing regulation, and reactive support

and voltage control (RSVC). Successful projects

could also be dispatched to provide energy

shifting, ramping support, and management of

excess generation services at the IESO level.

This procurement occurred in two stages: Phase

I launched in 2014 and a total of 33.54 MW of

capacity were contracted; Phase II launched in

2015 and saw 16.75 MW of capacity awarded to

proponents.


3

Stakeholder Identification and Outreach

This study’s research focuses primarily on

an in-depth review of existing published

studies and reports, Ontario energy market

data, and consultations with identified industry

stakeholders. While this study is primarily

concerned with the Ontario electricity system,

stakeholders were not necessarily limited to

those with a presence in Ontario. Five

stakeholder categories and over 50 contacts

were identified in an effort to ensure that a

broad base of perspectives could be captured.

The five categories are:

1. Energy Storage Technology Providers and

Developers

2. Local Distribution Companies and Utilities

3. Energy Storage Owners, Operators and

Site Hosts

4. Regulatory Bodies, Agencies, and

Academia

5. Industry Associations

During the research phase of this study,

each individual stakeholder was asked to

participate in an interview. A standard set of

questions specific for each stakeholder category

was developed as a baseline for gathering

information. During the analysis stage,

stakeholders may have been contacted again

for clarification or additional information.

Consultations with stakeholders provided

invaluable insights, not only to the Ontario

market, but also in other jurisdictions which

have actively engaged in energy storage system

development.


4

Current State of Distribution Connected Storage in Ontario

Although the topic of energy storage often

refers to emerging technology, there are several

projects throughout the province which are

planned, under construction, or have already

been commissioned in recent years. This

portion of the report outlines Ontario’s current

situation regarding technology, benefits,

revenue streams, challenges and barriers.

Deployed Technologies

There are four main types of technology

currently deployed in Ontario. These

technologies have varying capabilities and

energy capacities, but all strive to improve the

electrical grid. A brief description of each

technology and its capabilities can be found

below.

Battery – A battery, by definition, has one

positively charged material and one negatively

charged material. When ions travel from one

material to another, the battery is either

charged or discharged, thereby consuming or

releasing energy. Flow batteries use two

chemical solutions which flow through two

separate pumps and combine to release energy.

They have a potentially endless number

charge/discharge cycles, but have a lower

energy density than solid batteries. Solid

batteries are likely the most common

technology that people would consider for

energy storage. Unlike a flow battery, it uses a

solid electrolyte and solid electrode to store

positive and negative charges. When a

charge/discharge cycle is performed, some of

the ionic compounds are unable to be

separated, so over time a solid battery could

lose its ability to be charged and discharged.

Compressed Air – Compressed air facilities

use electricity to drive a motor and compressor

to pressurize air in a holding facility, either

underground or underwater. Air can be stored

indefinitely under pressure and can be released

allowing a generator to produce electricity

when needed. These facilities have the highest

energy capacity, although they have a lower

efficiency than other types of storage. The

efficiency of this technology has improved with

the advancement of heat storage, as heating air

upon depressurization is required for most

applications.

Flywheel – Electricity drives a motor

which causes the flywheel to start spinning,

storing electricity as kinetic energy. When

electricity is needed, the momentum of the

flywheel is used to turn a generator, releasing

electrical energy. Due to energy being stored as

momentum, flywheels tend to have low energy

retention and quickly discharge if not

constantly used. Flywheels can move from

fully charging to fully discharging almost

instantly, which makes them desirable for

applications which require fast response times.

Pumped Water Storage – This technology is

the oldest form of energy storage in Ontario

and has the most installed storage potential of

any of the mentioned technologies. Due to the

typical scale required for a project, this

technology is typically connected to the


5

transmission system and is therefore out of

scope for this study.

Current and Planned Projects

Although not an exhaustive list, some of the

more notable energy storage projects that are

currently operating or under development in

Ontario include:

A pilot project named POWER.HOUSE

consisting of 20 customer homes, each

with a 5 kW solar photovoltaic generator

with an 11.4 kWh lithium-ion battery

connected behind the meter. The systems

are controlled through software that

aggregates the individual energy storage

systems as a virtual power plant,

simulating a single 100 kW generator.

Benefits of this project include: protecting

the customer against power outages,

offsetting peak electricity rates, and

relieving strain on the grid during

periods of peak demand. This inventive

project won the Innovation Award in the

Distributed Storage Project category from

Energy Storage North America (ESNA).

There is a partnership with Thunder Bay

Hydro to expand the pilot project to other

local electric utilities [2].

Korea Electric Power Corporation has

recently completed development of the

Penetanguishene Micro Grid in

Penetanguishene, ON. The system is

comprised of a 750 kW power conversion

system, 500 kWh of battery storage, and

associated controls. The system has the

capacity to provide several hours of

backup power supply for approximately

400 customers and helps increase the

resiliency and operational flexibility of

the existing grid [3].

Opus One developed the Athletes’

Village for Toronto’s 2015 Pan Am

Games, which included energy storage

and electric vehicle charging stations. The

project is a microgrid demonstration

which uses storage to shift energy

produced during the day to supply load

at night [4].

Hydrostor Inc. has developed a 660 kW

to 1 MW compressed air energy storage

system in Toronto Hydro service

territory. This unique system converts

electricity into compressed air which is

stored in underwater accumulators. Heat

derived from compression is stored for

later use during generation. When

electricity is needed, the compressed air

is released from the accumulators and

stored heat is added to improve the

overall efficiency of the system. The

heated air travels to an expander that

enables a generator to produce power [5].

eCAMION, in conjunction with Toronto

Hydro and Ryerson University,

developed a novel pole-mounted energy

storage project in Toronto. The lithium-

ion 25 kW / 16 kWh system utilizes

batteries mounted to existing utility poles

and an intelligent controller developed

by Ryerson University that can

communicate with smart meters. The


6

system benefits include load levelling,

deferral of infrastructure upgrades, and

increased reliability and operational

flexibility of the grid [6].

eCAMION worked with Toronto Hydro

to install a 500 kW / 250 kWh lithium-ion

battery project for community energy

storage. The project is helping utilize

assets more effectively, smoothing load,

and for backup power supply [7].

NRStor has developed a 2 MW flywheel

project in Minto to provide frequency

regulation service by utilizing Temporal

Power’s flywheel energy storage

technology. The project is the first

commercial flywheel energy storage

project in Canada [8].

Hydro One Networks Inc. has planned a

Temporal flywheel system in Clear

Creek, ON to regulate the large voltage

swings caused by a 20 MW wind farm [9].

Customers were experiencing poor

power quality due to the intermittent

nature of wind power and the feeder

configuration. Construction has not yet

begun.

Opus One Solutions has collaborated

with Hydro One as the utility host, and

eCAMION as the battery provider, to

develop their Distributed Energy

Management and Storage Network

(DEMSN) Project. The project’s objective

is to maximize integration of solar

photovoltaic and other resources in the

distribution system by deploying a

battery energy storage system in

combination with Opus One’s smart grid

software applications [10].

RES Canada has developed a lithium-ion

battery storage project in Strathroy, ON.

The system is 4 MW / 2.6 MWh and

provides frequency regulation service to

the IESO under a three year agreement

[11].

NEDO and Oshawa Power and Utilities

Corporation have partnered to develop a

pilot project involving 30 homes in the

City of Oshawa [12]. The project involves

30 residential rooftop solar PV systems

that are combined with 10 kWh lithium-

ion batteries and sophisticated controls.

The system allows homeowners to better

manage their consumption and

generation, reducing their cost of

electricity, and providing a source of

backup power in the event of a grid

failure.

Convergent Energy and Power Inc. plan

to install 7 MW of lithium-ion batteries at

a substation in Sault Ste. Marie, ON.

Construction began in fall 2016, with the

system expected to be online in March

2017 [13]. This is a three year pilot

contracted through the IESO to determine

how it can improve grid reliability.

Hydrogenics uses power-to-gas for

energy storage. They have won 2 MW

procurement through the IESO for a

project in the Greater Toronto Area [14].


7

Ameresco Canada Inc. has won two solid

battery projects in IESO’s Phase II energy

storage procurement. Both facilities will

be 2 MW / 8 MWh arrangements to shift

excess generation to periods of higher

demand and support the grid [15].

Baseload Power Corp has won IESO

Phase II energy storage procurement for a

2 MW / 8 MWh flow battery. The main

purposes for this project are grid support

and arbitrage [15].

NextEra Canada will be commissioning

two lithium-ion projects which will be

dispatched by the IESO as required to

relieve excess generation and peak

demand on the grid. Each project will be

2 MW / 8 MWh [15].

NRStor Inc. partnered with Hydrostor to

commission a 1.75 MW / 7 MWh, fuel free

compressed air facility in Goderich, ON.

Its main focus will be storing excess

energy for later use. This project is

expected to begin construction in 2017 [5].

Panasonic ECO Solutions partnered with

the University of Ontario Institute of

Technology (UOIT) to develop a

MicroGrid and Research Park, consisting

of a 500 kW Lithium-ion battery storage

system and a 50 kW solar PV generator

[16].

SunEdison Canada has been awarded

three flow battery projects, totaling 5 MW

and 20 MWh. The projects will be used by

the IESO to store and release energy as

needed and for RSVC [15].


8

Project Technology Capacity Benefits

POWER.HOUSE Lithium-ion Battery 228 kWh Redundant power supply

Penetanguishene Micro

Grid

Battery 500 kWh Redundant power supply

Pan Am Games 2015 100 kVA, 125kWh Load shifting

Hydrostor - Toronto Compressed Air Varies Distribution line decongestion

eCAMION – Toronto

Hydro

Lithium-ion battery 25 kW, 16 kWh Infrastructure support

eCAMION - Toronto Lithium-ion battery 500 kW, 250 kWh Infrastructure support

NRStor - Minto Flywheel ±2 MW, 500 kWh Frequency regulation

HONI – Clear Creek Flywheel ±5 MW, 500 kWh Voltage control

Opus One - DEMSN Battery Voltage support, generation

integration

RES Canada - Strathroy Lithium-ion battery 4 MW, 2.6 MWh Frequency Regulation

NEDO – Oshawa Lithium-ion battery 10 kWh Load leveling

Convergent Energy –

Sault Ste. Marie

Lithium-ion battery 7 MW Reliability

Hydrogenics Power-to-Gas 2 MW Frequency Regulation

Ameresco – Phase II Solid Battery (2x) 2 MW, 8 MWh Peak shaving

Baseload Power –

Phase II

Flow Battery 2 MW, 8 MWh Grid support and arbitrage

NextEra – Phase II Solid Battery 2 MW, 8 MWh Grid support and arbitrage

NRStor Inc. – Phase II Compressed Air 1.75 MW, 7 MWh Grid support

SunEdison – Phase II Flow Battery 1 MW, 4 MWh

(2x) 2 MW, 8 MWh

Grid support

Table 1: Ontario Energy Storage Project Summary

The above list of notable projects is only a

sample of energy storage pilots and projects

that are either currently operating or being

developed in Ontario; it is clear that interest in

energy storage is increasing as technologies

advance and the benefits become more widely

understood. Multiple technologies of varying

size and capacity are being utilized to offer a

diverse array of benefits to system operators,

distributors, and end users.

Several key learnings emerged from the

IESO energy storage procurements. Some of the

more noteworthy lessons learned include:

Location of a storage project affects the

benefits it can provide.

Losses associated with both conversion

and storage (i.e. leakage, diffusion)

should be accounted for when energy

storage technology is selected.

Energy storage systems are limited by the

technology and economics of the system.

There may be periods when storage

facilities may not be able to respond to a


9

given signal as a result of the store being

full or empty.

All energy storage technologies have the

ability to withdraw energy from the grid,

however not all technologies are capable

of discharging the stored energy back

into the grid.

Three categories of energy storage were

identified in a report by the IESO:

Type 1 – Energy storage technologies that are

capable of withdrawing electrical energy

(electricity) from the grid, storing such

energy for a period of time and then re-

injecting this energy back into the grid

(minus reasonable losses). Examples include,

but are not limited to, flywheels, batteries,

compressed air, and pumped hydroelectric.

Type 2 – Energy storage technologies that

withdraw electricity from the grid and store

the energy for a period of time. However,

instead of injecting it back into the grid, they

use the stored energy to displace electricity

consumption (demand) of their host facility at

a later time. Examples include, but are not

limited to, heat storage or ice production for

space heating or cooling.

Type 3 – Energy storage technologies that

only withdraw electricity from the grid like

other loads, but convert it into a storable form

of energy or fuel that is subsequently used in

an industrial, commercial or residential

process or to displace a secondary form of

energy. They’re generally integrated with a

host process that uses that secondary form of

energy directly or are connected to a

transmission or distribution network for their

secondary form of energy (e.g., natural gas,

steam or coolant). Examples include, but are

not limited to, fuel production (hydrogen or

methane), steam production and electric

vehicles [15].

It should be noted that Type 2 and Type 3

energy storage technologies are not a primary

focus of this study report, since the stored

energy in these applications is not reintroduced

to the distribution grid.

Revenue Streams Available to Project

Owners

Energy storage systems have the ability to

provide more than one benefit to a distribution

grid at any given time. However, not all of the

benefits provided from an energy storage

system can be monetized. When a project is

installed, it can often have portions of energy

capacity allocated for different uses, such as

redundant power supply and power quality

improvement. While stacking benefits can lead

to a highly profitable project, the project owner

would ideally have the ability to be reimbursed

for services provided to each beneficiary. Too

often, only the main benefit of a project is

monetized, parting with potential earnings

from secondary benefits. A Value Matrix is

provided in this report, in Appendix A, to

identify various revenue streams available to a

project owner. The Value Matrix assigns a

monetary range to each benefit identified in

this report. To review the calculations used for

monetary ranges, please see Appendix B.

Table 2 and Table 3 below use the Value

Matrix to depict possible yearly totals for

currently monetizable benefit streams and

provide definitions of those benefits. A 1 MW /

4 MWh, technology agnostic system is used in


10

this study in order to allow for more

meaningful comparisons across disparate

technologies and use cases. In addition, a 1 MW

system with a 4 hour discharge cycle allows for

easier scaling of costs and benefits to larger

proposed system sizes. The IESO Phase I and

Phase II procurements have seen similarly

sized systems proposed, and projects of this

size are more likely to be installed in the

distribution system. Finally, discussions with

stakeholders supported the notion that a

standard 1 MW / 4 MWh energy storage system

would be the most reasonable for comparative

purposes.

Benefit Monetary Range ($

per MWh Delivered)

Assumed Number

of MWh per year Total $ Per Year

Market Arbitrage $13.90 -$23.50 1460 $20,294 - $34,310

Distribution System Upgrade

Avoidance $12.87 -$133.56 1460 $18,790 - $194,998

New Generation Capacity

Avoidance $12.15 -$25.23 1460 $17,739 - $36,836

Redundant Power Supply

(Reliability) $3,900 -$26,000 10 $39,000 - $260,000

Non-Spinning Reserve

Availability $0.20 - $30 1460 $292 - $43,800

Spinning Reserve Availability $0.20 - $54 1460 $292 - $78,840

Reserve Activation $0.40 - $135 730 $292 - $98,550

Power Quality Improvement $6.06 -$11.35 3025 $18,332 - $34,334

Frequency Regulation $45 - $65 3025 $136,125 - $196,625

Voltage Control $8.30 - $58.50 3025 $20,294 - $34,310

Black Start $5.85 - $36 10 $58.50 - $360

Reduced Dispatching of

Peaker Facilities $110 - $170 1460 $160,000 - $248,200

Global Adjustment Charge

Reduction (Class A) $80,000-$105,000 5 $400,000 - $559,310

Table 2: Currently Monetizable Benefits, from Appendix A, Value Matrix


11

Benefit Description

Market Arbitrage Value that could be derived strictly through purchasing energy at a low cost

and selling at a high cost, using Ontario's market price signals.

Distribution System

Upgrade Avoidance

Value of avoiding distribution system upgrades as a result of dispatching

energy storage. For example, congestion mitigation may lead to avoidance of

feeder expansion.

New Generation

Capacity Avoidance

Value of using stored energy to reduce demand on the distribution system such

that the development of new generation facilities is avoided.

Redundant Power

Supply (Reliability)

Value of using stored energy to provide power to loads during traditional

distribution system outages. The lower end of the range typically represents

residential load and the higher end of the range represents commercial,

industrial, or load of a critical nature.

Non-Spinning

Reserve Availability

Value paid to resources that participate as a part of "Non-Spinning Reserve", or

generation capacity which can inject power after a short delay.

Spinning Reserve

Availability

Value paid to resources that participate as a part of "Spinning Reserve", or

generation capacity which can inject power immediately.

Reserve Activation Value paid to resources that participate as a part of "Spinning Reserve"

programs, once activated for supplying reserve.

Power Quality

Improvement Value for improving overall power quality to consumers.

Frequency

Regulation Value of dispatching energy storage to provide Frequency Regulation for IESO.

Voltage Control Value of dispatching energy storage to provide Voltage Control for IESO.

Black Start Value of dispatching energy storage to provide Black Start services.

Reduced

Dispatching of

Peaker Facilities

Value of dispatching energy storage facilities instead of peaker facilities to meet

peak demand, assist in ramping, and assisting with load following.

Global Adjustment

Charge Reduction

(Class A)

Value of reducing consumption during all five Ontario coincident peaks by 1

MW.

Table 3: Benefit Definitions, from Appendix A, Value Matrix

This study assesses four typical positions

on a distribution system that an energy storage

project could be connected to. “At TS”, or “at

the feeder head”, indicates that a project is

located closely to the Transformer Station,

(“TS”), and the beginning of a feeder. “Middle

of Feeder” means that the project is located

reasonably close to the center of a feeder, not

necessarily geographically, but electrically.

“End of Feeder” projects are located close to the


12

furthest downstream loads of a feeder. Finally,

projects that are designated “Behind Meter” are

located on the load or customer side of a meter,

regardless of whether they are billed as

residential, Class A, or Class B consumers.

Not all connection locations are suitable for

all revenue streams. For instance, Global

Adjustment Charge Reduction cannot be

performed under any circumstance other than

behind a Class A customer’s meter due to the

way Global Adjustment charges are calculated.

A Benefit Matrix is provided to indicate which

locations are suitable for a given benefit stream.

A green checkmark indicates that the location

should be suitable, yellow that a location may

be suitable, and a red “X” indicates that the

location is unsuitable for that benefit stream.

Distribution Connected Energy Storage Location1

Currently Monetizable Benefits At TS Middle of

Feeder

End of

Feeder

Behind

Meter

Market Arbitrage

Distribution System Upgrade Avoidance

New Generation Capacity Avoidance

Redundant Power Supply (Reliability)

Non-Spinning Reserve Availability

Spinning Reserve Availability

Reserve Activation

Power Quality Improvement

Frequency Regulation

Voltage Control

Black Start

Reduce Dispatching of Peaker Facilities

Global Adjustment Charge Reduction (Class A)

Table 4: Direct Benefit Matrix

1 Some benefits may be viable at other locations if an aggregator could be used. For simplicity this assessment

only considers single connections.


13

Barriers to Current Projects

One of the focal points of this study is to

identify and present barriers inhibiting energy

storage. Below is a generalized table outlining

some of the barriers associated with energy

storage projects. In other sections of this report

these barriers are expounded upon to inform

the reader about the issues at hand.

General Barriers to Energy Storage Adoption in Ontario Distribution Grids

Regulatory Commercial/Financial Physical/Technical Social

IESO rules dictate that a single

unit cannot provide operating

reserve and regulation at the

same time. For a storage project

to provide both it must split a

multi-unit project into

regulation providers and

reserve providers, or one project

can one or the other at different

times of day, and any

combination of these two

solutions.

Project financing and

insurance may be difficult to

obtain from traditional sources

due to uncertainty of

technologies and revenue

streams

Protection philosophies

must account for how

reverse power flow can

affect worker safety and

equipment longevity

General lack of awareness

and education of energy

storage applications and

technology among

consumers and

distributors

Ambiguity with regards to the

definition of energy storage in

current regulations (ex: Ontario

Energy Board Act, 1998, 71(3),

where storage facility was

originally written to mean gas

storage facility)

Global Adjustment, Demand,

and Debt Retirement costs

incurred during charging can

negatively impact potential

project financial viability

Geographical and network

topology limits potential

site locations (ex:

compressed air energy

storage requires a cavern

and/or access to bodies of

water)

Uncertainty of new Cap

and Trade regulations on

energy storage

Net Metering O. Reg. 541/05

currently applies only to

renewable generation; there is

uncertainty of its application to

energy storage. Legislative

changes, which may include

energy storage, are under

discussion.

Uncertainty regarding existing

equipment suppliers ability to

meet increasing demand for

energy storage products;

uncertainty of warranties in

future

Lack of market-proven

methods to aggregate

numerous smaller energy

storage systems across a

geographical area (i.e.

residential behind the

meter systems, electric

vehicles).

Obtaining and paying for

necessary permits,

environmental and electrical

studies before being able to start

a project makes some smaller

projects impractical.

Difficulty in quantifying

benefit streams and

compensating project owners

for services delivered.

Table 5: General Barriers to Energy Storage Matrix


14

Ontario Distribution Connected Storage Benefit Assessment

This section will describe the complexities

involved with connecting energy storage

systems to an Ontario distribution network.

Some of the factors that can affect viability of

an energy storage facility on a distribution grid

are: location of an energy storage system (ex.

beginning or end of feeder), topology of the

distribution grid (i.e. radial, loop, or mesh),

geographic environment (i.e. urban, suburban,

or rural), and size of the connecting Local

Distribution Company (“LDC”). The specific

combination of these factors will also influence

which potential benefits can be realized and

monetized by a project.

Location

Electrical location of an energy storage

project on a distribution feeder will impact

which benefits can be provided. For example, a

black start facility cannot be located at the end

of a feeder because it would likely be unable to

provide sufficient energy to revive a portion of

the transmission system from this location.

Conversely, a project for voltage control is less

effective if located at the start of a feeder

because of losses between the project and the

voltages it is trying to correct.

Distribution Grid Topology

The topology and configuration of a

distribution feeder will affect current and

voltages, restoration possibilities, expansion

options, and fault conditions. Radial systems

are characterized by a single source to load.

Voltages and currents along a radial system

start high at the source and then drop as the

source becomes further away. An advantage of

this topology is its simplicity, but the tradeoff is

that all customers downstream of an outage

point must wait for power to be restored. Loop

systems have more than one path to each load.

This means that current can flow in more than

one direction, therefore aiding in continuity of

service since a portion of the distribution

system that requires work can be isolated while

leaving other customers in service. This

topology is notoriously difficult to analyze

because the flow of current can change based

on load and generation, and computer

programs need more algorithms to solve the

system over a similarly sized radial system.

One way to gain advantages from both

topologies is to create a loop-based system

leaving key points in normally open positions.

This creates a system that is technically radial

but also has the ability to feed customers

through alternate routes in the event of an

outage.

Project developers should work with the

host LDC in order to better understand how

the distribution grid topology can affect the

intended benefits of an energy storage system.

Radial topologies cannot change their

configurations; therefore the energy storage

system will always be in the same relative

electrical position between the source of

generation and its loads and may be unable to

provide energy to the targeted area during an

outage. Inside of a looped system, the electrical

position of a storage project could change,

potentially rendering it unavailable to provide

the benefits for which it was intended. As the


15

complexity of grid topology increases from

radial to loop, the complexity of evaluating the

benefits attainable from energy storage also

increases.

Size of Distributor

The size of an LDC (generally referring to

its territory, asset base, load density, and

staffing) can play a significant role in how

energy storage affects the distribution network.

Larger utilities tend to have more resilient

urban grids and larger loads, where sudden

changes in load or generation have little effect

on voltage and frequency. Large utilities may

also have monitoring equipment and remotely

controlled assets which may make it quicker

and easier to connect and control storage

projects.

Medium sized utilities tend to have urban

feeders or feeders that alternate between urban

and rural densities. They may or may not have

monitoring equipment and are more likely to

experience greater impacts from medium and

large projects due mainly to smaller feeder

loads. However, it is noted that medium and

small utilities leverage Hydro One’s rules and

requirements for their own distribution

systems where assets are sufficiently similar.

Small utilities often have multiple

noncontiguous service areas and may share

feeders with other distribution companies.

Generally, smaller LDCs and their distribution

grids may be more exposed to the impacts of a

given energy storage system than are larger

LDCs. That is, for smaller LDCs, a given energy

storage project may represent a larger

proportion of their total load and may directly

impact a proportionately higher number of

customers than in larger LDCs. Also, smaller

LDCs tend to have fewer resources available to

support the research and development of an

energy storage projects in their territory.

Geographic Environment

When choosing a technology for storing

energy, one must consider the geographical

requirements for the technology and

geography of the planned site. Rural areas

typically consist of smaller loads which are

generally serviced by a longer feeder. Longer

feeders can cause voltages to drop considerably

over the length of the feeder. This could

possibly lead to high voltages and overloaded

assets at the feeder head and low voltages with

under-utilized assets at the feeder end.

Urban areas tend to experience greater

congestion on a given feeder due to their

relatively smaller feeder length and the greater

density of generation and loads. This higher

level of congestion on a feeder may limit the

ability to connect an energy storage facility at

this location.

The physical space available can also

impact the viability of an energy storage

system in a particular geographic environment.

Some technologies will require their own

building and can have a large physical

footprint, which may not be available in dense

urban centers. For example, compressed air

energy storage requires either a cavern or a

body of water in order to store energy, which

may not be available in a particular location.


16

Possible Benefits

A “Benefit Matrix” is provided in

Appendix A which summarizes the potential

benefits, both direct and indirect, for energy

storage projects at various locations on the

distribution grid.

As indicated in the Benefit Matrix, there are

a number of revenue opportunities available to

energy storage project owners. The challenge

lies in receiving compensation for the benefits

provided.

Monetary Value of Benefits

A “Value Matrix” is provided in Appendix

A which summarizes the potential monetary

ranges of benefit quantification. Appendix B

also provides the benefit quantification

methodology used to determine the associated

range of monetary values for each listed

benefit.

The quantification of these benefits is

problematic since exact financial values are

project-specific. Several stakeholders were

reluctant or prevented from disclosing project-

specific values due to privacy concerns or

existing non-disclosure agreements.

Furthermore, in the Ontario electricity market,

participants bid into a competitive market for

the provision of a particular service. This adds

further complexity when attempting to

determine the precise value of a benefit

attributable to the system owner or beneficiary.

As a result, it is necessary to quantify benefits

into a range of possible values.

Beneficiaries of Energy Storage

Each energy storage application would

have one or more secondary beneficiaries; these

additional beneficiaries are project-specific.

Factors which affect secondary beneficiaries

could be: application, location, operational

characteristics of an energy storage system, and

desired combination of stacked benefits a

project provides.


17

Ontario Distribution Connected Storage Barrier Assessment

IESO and LDC Connection and

Communication Costs

A necessary cost for a storage project is

associated with connecting to a distribution

system. This cost depends on what must be

built or upgraded for the project to safely

connect. It could include simply connecting to

an existing transformer, building a new line on

a feeder, or upgrading a transformer station, to

name a few possibilities. Many LDCs use

Hydro One’s Technical Integration

Requirements, or TIR, to determine what must

be done for a customer to connect to their

distribution system, although some will have

their own requirements. LDCs may require a

Connection Impact Assessment, or CIA, to

determine the effect of adding a project to their

system depending on project sizing.

Requirements set out by individual LDCs

and required upgrades or expansions will

dictate the cost associated with connection. A

common theme through stakeholder outreach

was that the connection costs from LDCs were

not unreasonable except for the case where

Transfer Trip, “TT”, is required. Transfer Trip

signals are sent from remote locations to the

substation or transmission station to quickly

communicate fault and abnormal conditions to

hasten circuit breaker actions. The cost of

upgrading a transformer station to enable TT

signals from a larger project is sometimes

prohibitive for a project. Some stakeholders

spoke of the unequitable cost allocation for

upgrades, as the first project to connect bears

the bulk of costs and subsequent projects

benefit from the first’s investment.

Permits and Licensing

Required licensing and permits can vary

greatly from project to project. Factors that

affect what is required include: renovations

and/or new buildings, proximity to wooded

areas and waterways, use of public or crown

land, necessary alterations to roadways and

railways, affected LDC, and municipality or

county a project is to be located in. This report

combines information from several small,

medium, and large municipalities to determine

the breadth of permits that could be required

for a project. It is incumbent on the project

owner and developers to acquire all

appropriate permits for their project.

Appendix C lists different types of permits

and their possible costs. Please note that this is

not an exhaustive list as some municipalities

may require different permits than the

municipalities reviewed in this report.

GA and Demand Charges

One of the barriers frequently discussed

among stakeholders is the obstacle that

Demand and Global Adjustment (“GA”)

charges create for economic viability of a

project. This section discusses the impact of GA

and Demand on a hypothetical energy storage

project connected to a distribution system.

Demand Charges

When a storage project draws from the grid

to charge, it incurs Demand and Usage fees


18

because it is using the distribution grid to

transfer electricity as would any other load.

Demand costs depend on the largest draw for a

month because distribution companies are

required to be able to meet the peak need of all

their customers. As can be seen in Table 6, the

total yearly Demand charge for a 1 MW peak

load would be $88,549. Usage charges are

calculated by the cost of the electricity itself.

Table 7 outlines the Usage charges for a

hypothetical 4 MWh consumption per day. As

can be seen from the table, Usage charges only

account for $7,300 per month, less than 10% of

the Demand charge.

Demand Charges (1 MW, 4 MWh, cycled daily)

Charge Name Monthly Charge Year Total

Facility Charge for connection to Common ST Lines $/kW 1.1740 $14,088

Rate Rider for Disposition of Deferral/Variance Accounts

(General)2

$/kW 0.3151 $3,781.20

Retail Transmission Rate – Network Service Rate3 $/kW 3.3396 $40,075.20

Retail Transmission Rate – Line Connection Service Rate $/kW 0.7791 $9,349.20

Retail Transmission Rate – Transformation Connection

Service Rate

$/kW 1.7713 $21,255.60

Total Charges $/kW 7.3791 $88,549.20

Table 6: Demand Charge Calculation (1 MW, 4MWh, operating daily)

Usage Charges (1 MW, 4 MWh, cycled daily)

Charge Name Monthly Charge Year Total

Rate Rider for Disposition of Global Adjustment Account

(2016)

$/kWh (0.0010) -$1,460

Wholesale Market Service Rate $/kWh 0.0036 $5,256

Rural or Remote Electricity Rate Protection Charge

(RRRP)

$/kWh 0.0013 $1,898

Ontario Electricity Support Program Charge (OESP) $/kWh 0.0011 $1,606

Total Charges $/kWh 0.0050 $7,300

Table 7: Usage Charge Calculation (1 MW, 4 MWh, operating daily)

2 This will change each year depending on variance accounts for each utility 3 If charging occurs between 7PM and 7AM, this charge does not apply


19

Class B Global Adjustment

In Ontario, Class B load customers are

charged GA based on usage (kWh) and the

monthly estimates for GA. Table 8, below,

shows the amount that a 1 MW / 4 MWh

energy storage project would have paid during

2016 assuming it fully charged and discharged

every day. Notably, GA accounts for more cost

than Demand, Usage, and fixed utility charges

combined.

Month 1st Estimate ($/MWh) Days in a Month Class B GA

January $84.23 31 $10,444.52

February $103.84 28 $11,630.08

March $90.22 31 $11,187.28

April $121.15 30 $14,538.00

May $104.05 31 $12,902.20

June $116.5 30 $13,980.00

July $76.67 31 $9,507.08

August $85.69 31 $10,625.56

September $70.6 30 $8,472.00

October $97.2 31 $12,052.80

November $122.71 30 $14,725.20

December $105.94 31 $13,136.56

Total $98.08 365 $143,201.28

Table 8: Global Adjustment Calculation

Exceptions - Class A Global Adjustment

Class A customers have the unique ability

to affect how much Global Adjustment they are

required to pay. The amount they pay is solely

dependent on their specific contribution to the

peak provincial load during the top five

Ontario peak demand hours in a given year.

Therefore, installing an energy storage project

behind the meter of a Class A account may not

increase GA but instead, could significantly

reduce GA charges; provided the storage

facility were discharged such that it reduced

the overall demand of the load account during

each of the top five Ontario peak demand

hours. Appendix B, Section 13. Global

Adjustment Charge Reduction (Class A),

provides calculations which demonstrate that a

Class A load account with a 1 MW / 4 MWh

energy storage facility could save more than

$500,000 annually in GA costs by managing

storage discharges such that they align with

Ontario’s top 5 peaks for a year.

With the most recent regulatory updates

customers with 1 MW of load, or 500 kW of

manufacturing load, can be included in the

Class A customer class.

Exceptions – Demand Charges

Demand Charges related to the charging of

behind the meter storage facilities for Ontario’s


20

Class A and Class B customers depend on

when a facility charges in comparison to the

normal operating hours (or more specifically

the load profile) for a customer. Demand

charges for an application could theoretically

be ignored if a storage project is charged

during the hours when the facility has low

electricity demand, since that project does not

increase the facility’s normal peak load.

Exceptions - Residential Customers (Behind the

Meter)

With a residential class customer, rates for

energy consumption (kWh) are time-of-use

based where GA charges are included and form

a portion of the time-of-use rate. Residents

using a storage facility for energy arbitrage

would be able to gain a fixed amount of

compensation. The difference between On-Peak

and Off-Peak rates is insufficient to motivate

widespread adoption of residential storage

initiatives. An additional motivating factor,

such as emergency power, may be required for

a project to be considered worthwhile.

Other Commercial Issues

There are a number of commercial issues

that can have a significant impact on the

viability of an energy storage project in

Ontario. In addition to the detailed discussion

of Global Adjustment and Demand above, each

of the following potential barriers should be

duly considered.

Financial

With early adoption projects, many

financial institutions are unwilling to

competitively finance a project because of

uncertainty surrounding its revenue

capabilities.

Insurance companies are hesitant to

insure facilities with relatively unknown

insurance risk factors.

Implications of new Cap and Trade

regulations, which commenced on

January 1st, 2017, have unclear effects on

financials of an energy storage project.

Future impacts of the regulation are

unknown.

It is a challenge for energy storage

owners to clearly quantify all benefit

streams and be appropriately

compensated by benefiting parties,

particularly for the indirect benefits

identified in this study, and more

particularly when there is more than one

benefitting party.

Technology

With the escalation of interest in energy

storage, it is uncertain if producers will

be able to meet market demand for their

products.

New companies may have consumers

concerned with their ability to meet

warranty demands and the longevity of

the company itself for further technical

support.

Consumers may delay purchases with the

anticipation of newer technology.

Alternatively, some consumers are

worried about their ability to find

replacement parts for a possibly obsolete

project before its end of life.

The current workforce may not be able to

meet the need for qualified personnel to

operate the technology and perform

scheduled maintenance and repairs.


21

Other Non-Commercial Issues

There are a number of non-commercial

issues which can have a significant impact on

the viability of an energy storage project. In

addition to the detailed discussion of permits in

a previous section, each of the following

potential barriers should be duly considered.

Safety

Employee safety is always the number

one concern when it comes to new and

developing technology. People from

many different career paths must be

trained in how to approach and safely

work with storage projects. These career

types include but are not limited to:

powerline workers, technicians, first

responders, skilled trades, and

maintenance.

Protecting public safety when dealing

with electrical equipment is always a

concern. There needs to be sufficient

safeguards to protect the public against

failed or malfunctioned equipment.

Protecting equipment is a justified

concern for project owners and operators.

Much of the existing distribution system

protection equipment is geared towards

generators and loads, but storage is both

and neither at the same time. Equipment

must be programmed or new products

developed to ensure a project’s longevity.

Standards

There is currently a lack of installation

standards for contractors and LDCs to

adhere to. Without a peer-reviewed

standard to comply with, installations

run the risk of overlooking a crucial

element or could accidentally be under-

designed.

Individual pieces of equipment in an

energy storage project will have technical

standards, but may not have a system-

level standard that brings them together

as one unit.

There are currently no standard

operating procedures in many LDCs or

other companies for storage technology.

These will need to be developed and,

more than likely, be technology specific.

Social

Consumers and distributors have a

general lack of awareness and education

about energy storage and its capabilities.

They are unsure of how it could affect

them and how it compares with

traditional methods of power

distribution.

With the new Cap and Trade regulation

which came into effect on January 1, 2017

many people are unsure of how

consumers will change their consumption

habits. It is currently unclear how Cap

and Trade will affect the behaviour of

electricity consumers, LDCs, and gas

suppliers.

Technical Requirements

Traditional protection philosophies

generally do not account for reverse

power flows. With the nature of energy

storage both consuming and releasing

energy, protection philosophies will need

to be able to adjust and determine when

an issue actually occurs.

LDCs may have different connection

requirements for projects in their


22

territories which could restrict potential

host locations.

Not all technologies are suited for every

application. One must consider a project’s

main purpose to determine an

appropriate technology.

Monitoring and dispatching storage will

need to be done remotely in most cases.

Many small and medium LDCs do not

currently have the ability to monitor

signals from a project, which could result

in not knowing which way current is

flowing through their system.

As previously stated, geographical and

network constraints could limit the

technology and project size.

Although aggregation of small systems is

possible, as seen through PowerStream’s

POWER.HOME project and aggregation

of peaksaver PLUS ® thermostats, the

commercial viability of aggregating bi-

directional flows of energy on a larger

scale remains to be seen.

Legislative and Regulatory

Current legislation and regulations need

to reduce ambiguity around energy

storage, its roles, and definitions.

Net metering regulations in Ontario have

changed. Net metering is permissible

with a storage component, however some

aspects of net metering (i.e. virtual net

metering, multi-site settlement, etc.) are

still uncertain. Net metering is also still

not available in storage-only situations.

Current projects contracted and

dispatched by IESO have contract lengths

much shorter than the expected life of the

asset.

Current market rules were created to

account strictly for generators or loads

and did not envision the unique

characteristics of energy storage systems.

For example, current rules prohibit the

concurrent provision of both Operating

Reserve and Regulation services, despite

the capability of some technologies to

provide both at the same time.

Required number of permits in some

cases can make small projects impractical.

It is currently unclear how Cap and Trade

will affect the electricity market and the

technologies that support the electricity

grid.


23

Example Use Cases

To guide the reader in how to use the

Value Matrix and Benefit Matrix (Appendix A),

scenarios are presented below to showcase a

broad range of possibilities. Each case outlines

a location along a distribution feeder and one

or more benefits suitable to that location. The

reader can follow along by referring to the

Benefit Matrix and Value Matrix to find the

location and benefit(s) utilized.

The use cases have been developed absent

of energy storage technology-specific costs.

However, the use cases do include common

up-front and ongoing costs that Ontario-based

projects would incur. This was done in order to

allow the reader to determine if the technology

they wish to use (and related cost structure)

would be financially viable for the given use

cases (and related benefits). One of the

technology-specific costs of operation is losses

incurred during the charge and discharge cycle

of a storage project. Losses can vary greatly

depending on the technology and duration of

storage. For simplicity, losses were not

included so that the reader can account for

technology and project specific losses in each

case. In general, accounting for losses will

decrease revenue potential for each use case.

All of the use cases contained herein

specify a generic 1 MW / 4 MWh storage

project, also, for uniformity. As one would

assume, scale could play a significant role in

the financial viability of a project and a use case

may become more or less favourable if its scale

changes.

Use Case Assumptions

All use cases assume a directly connected

project (distribution system) with Class B

customer class, except for Case 5 which

assumes behind the meter of a Class A

customer

All use cases assume there are no

technology related losses in the

charge/discharge cycle

GA charges are calculated using

Ontario’s 2016 first estimate values

Demand and usage rates are determined

through stakeholder input and Hydro

One Network Inc.’s 2016 rate case as

approved by the Ontario Energy Board

Costs and benefits are subject to an

inflation rate of 2% per year

Two assumptions are considered

regarding the inflation of Global

Adjustment and Demand; one at 2% and

one with 5% growth per year

15 year project life is assumed

Projects do not include carrying costs

related to financing (i.e. interest, etc.)

How to Interpret Use Case Analysis

The Value Matrix has been developed to

provide a range of possible values for a given

benefit stream. Note that projects may be able

to receive more or less value for each benefit

stream depending on project details related to a

specific application. Figure 1 is provided below

to illustrate to the reader how the graphs and

analysis were derived for each of the five

specific use cases herein, for the purpose of

interpreting results. The figure shows the


24

present value of a hypothetical project’s benefit

streams, net common costs (permits, Demand,

Usage, and GA), as well as the possible range

of stacked benefit values year over year for 15

years. The actual use cases presented in this

report compress the year over year data points

into a single net present value range. However,

for each use case the expanded graphs, similar

to Figure 1, can be referenced in Appendix D.

For a project to be financially viable, it is

reasonable to assume that the present value of

technology-specific capital and operational

costs would need to be less than the present

value of the monetizable benefits net of the

common costs. Beyond this, it is also reasonable

to assume that the project owner would apply

an appropriate rate of return to determine

financial viability. As stated previously, the

values shown indicate a possible range, so it is

incumbent upon a project owner to evaluate

where, within the range of possible values,

their project may be based on the specific value

if benefits it can monetize.

Note that non-monetizable (or indirect)

benefits are also reflected in present value

context on all use case graphs.

Figure 1: Example Use Case 15 Year Lifecycle


25

Case 1 – At TS, Frequency Regulation

Case 1 assumes locating the project in close

proximity to a transformer station. Using the

Benefit Matrix, one can see that there are

several benefit streams which are well suited to

projects located at the beginning of a feeder.

Case 1 seeks to provide Frequency Regulation.

The Value Matrix indicates that the monetary

range for Frequency Regulation is $45 -

$65/MWh of services provided. This case does

not include any indirect benefits.

Direct

Benefits

Provided

Value Per MWh ($) MWhs

Delivered Annual Value

Low High Per Year Low High Assumptions & Comments:

Frequency

Regulation $ 45.00 $ 65.00 3025 $136,125 $196,625

876000MWh/289.9MW =

3023h/year per facility MW

scheduled.

MWh per year:

= (1MWh * 3025h/year)

= 3025 MWh/year.

TOTAL

ANNUAL

BENEFIT:

$ 45.00 $ 65.00 $136,125 $196,625

Table 9: Benefit Streams - Case 1

Monthly Cost Per

MW/MWh ($)

MW/MWhs

Delivered Total Annual Cost (Year 1)

Common Cost Low High Per Year Low High

Total Demand Charges $7,380 - 1 MW $88,549

Total Usage Charges $5 - 3025 MWh $15,125

Global Adjustment Charges $70.60 - $122.71 3025 MWh $ 287,374

Ongoing Communication

Costs $60 $75 - $720 $900

Total Fixed Utility Charges $ 15,384 - - $ 15,384

TOTAL ANNUAL COST: $407,152 $407,332

Table 10: Monthly Common Costs - Case 1


26

Monthly Cost Per MW/MWh ($)

One Time Common Cost Low High

Building Permits $2,000 $25,000

Distribution System

Connection Costs $125,000 $400,000

TOTAL ONE TIME COST: $127,000 $425,000

Table 11: One Time Common Costs - Case 1

Figure 2: Present Value of Benefits and Costs - Case 1

Above is a chart summarizing the financial

scenario outlined by Case 1’s financial tables. A

present value has been determined net of

common costs for a 15 year project life. To view

a more detailed chart with costs and revenues

for each year, see Appendix D.

Based on the financial information

presented in Figure 2, one can surmise that the

project’s common costs outweigh possible

benefits, regardless of technology-specific

capital costs. In this case, the project owner

must reduce common costs (possibly as a result

of regulatory / market rule changes) or increase

the benefit value (possibly through stacking

additional services provided by the storage

facility) in order for this project to be

economically viable.


27

Case 2 – At TS, Enabling Renewables

Case 2 also assumes that an energy storage

project is located at the beginning of a

distribution feeder. This project’s main purpose

is to enable greater penetration of renewables,

specifically an assumed 10 MW wind farm,

although there is a secondary benefit of

reducing peaker facilities considered. Both of

these are well suited to a project located in

close proximity to a transformer station, as can

be seen in the Benefit Matrix. The Value Matrix

is used to determine the monetary range for

these benefits. This case includes two indirect

benefits; Excess Generation Mitigation and Cap

and Trade Benefit. These two benefit streams

are currently unable to be monetized by an

energy storage facility owner in Ontario’s

electricity market.

Benefit

Provided



Low High Per Year Low High Assumptions & Comments:

Reduced

Dispatching

of Peaker

Facilities

$ 110.00 $ 170.00 3100 $341,000 $ 527,000

Adding the ability to shift energy

to peak times will reduce the

need for the peaker fleet. Values

reflect a competitive price for a

peaker facility.

If a Power of Purchase

Agreement cannot be reached

with the IESO, then these values

will reflect market prices.

Indirect

Benefits Low High In 1 Year Low High Assumptions & Comments:

Enables

Higher

Penetration

of

Renewables

$ 80.00 $ 130.00 3100 $248,000 $ 403,000

Wind generation is typically

between 1.2MW and 3.8MW

depending on the month.

Number of curtailed hours is

assumed to be proportional to

the total installed capacity of a

wind farm.

Excess

Generation $50.00 $116.09 1500 $75,000 $174,135

Half of the MWh delivered by

the system for enabling higher

penetration of renewable

generation is assumed to reduce

excess generation.

Cap and

Trade

Benefit

$0.33 $6.69 3100 $1,023 $20,739

All of the MWh delivered by the

system will reduce the need for

peaker facilities, thereby

reducing the amount of cap and

trade needed.

TOTAL

ANNUAL

BENEFIT:

$ 240.33 $ 422.78 $665,023 $1,124,874



28

Monthly Cost Per

MW/MWh ($)

MW/MWhs





Global Adjustment Charges $70.60 - $122.71 3100 MWh $294,499


Costs $60 $75 - $720 $900

Total Fixed Utility Charges $ 15,384 - - $ 15,384

TOTAL ANNUAL COST: $ 414,652 $414,832

Table 13: Common Costs – Case 2




Distribution System





29








Case 2’s financial scenario indicates that

there is a possibility for it to be economically

viable depending on technology-specific costs.

This use case would be significantly more

profitable if the project owner could also be

compensated for the indirect benefits provided.

Under current market rules, the present value

of technology-specific capital and operational

costs for the assumed 1 MW, 4 MWh system

would need to be less than $1,349,937 to break

even, assuming the highest calculated direct

benefit values are achievable.

Case 3 – Middle of Feeder, Distribution

Upgrade Avoidance

This use case’s main purpose is to avoid a

distribution system upgrade. Using the Benefit

Matrix, one can determine that the two most

suitable locations are at a transformer station

and in the middle of a feeder. For this case,

middle of a feeder is chosen to relieve


30

congestion on a hypothetical conductor. While

shifting load from peak consumption periods

to lower consumption periods, it can be

assumed that the project will gain revenue

from Market Arbitrage. Shifting load will also

have the added indirect benefit of relieving

excess generation and will have Cap and Trade

value through reducing peak generation

requirements (assuming these peak

requirements are met using natural gas fired

generation facilities).

Value Per MWh ($)

MWhs


Benefit

Provided Low High Per Year Low High Assumptions & Comments:

Distribution

System

Expansion

Avoidance

$12.87 $133.56 1460 $18,790 $194,998

It is assumed that the application

will discharge on daily basis.

MWhs per year:

= 365 cycles * 4 MW

= 1460 MWh

Market

Arbitrage $13.90 $23.50 1460 $20,294 $34,310

This reflects the dollar amount

generated through load

displacement arbitrage on a daily

basis.

Indirect

Benefits Low High Per Year Low High Assumptions & Comments:

Excess

Generation

Mitigation

$50.00 $116.09 1460 $73,000 $169,491

By charging during lightly loaded

periods and discharging during

heavily loaded periods the system

will be able to mitigate excess

generation in Ontario.

Greenhouse

Gas

Mitigation

$0.33 $6.69 1460 $482 $9,767

The system will be able to lower Cap

and Trade by charging during

periods of high renewables and

discharging during times when

peakers are required.

TOTAL

ANNUAL

BENEFIT:

$77.10 $279.84 $112,566 $408,566



31

Monthly Cost Per

MW/MWh ($)

MW/MWhs




Global Adjustment Charges $70.60 - $122.71 1460 MWh $139,636.23


Costs $60 $75 - $720 $900

Total Fixed Utility Charges $ 15,384.60 - - $ 15,384.60

TOTAL ANNUAL COST: $ 163,040.83 $163,220.83

Table 16: Common Costs - Case 3




Distribution System





32








Under current market constructs, this

project would not be feasible given that the

maximum present value of the direct benefits

(net of common costs) is less than zero. The

project owner would need to be able to

monetize the identified indirect benefits and/or

reduce common costs, in order to make the

project economically viable before even

considering the impact of the technology

specific costs required to commission the

necessary storage facility.

Case 4 – End of Feeder, Reliability

One of the popular benefits of energy

storage is increasing reliability of power

through backup reserves. Using the Benefit

Matrix, projects with this goal should be

located closely to the load that requires

redundancy. For this reason, the project’s

location for this use case is at the end of a


33

feeder. The Value Matrix can be used to

determine that the value of redundant power

will vary greatly depending upon the nature of

the load of the consumer(s). This is intuitive as

residential customers are not usually willing to

pay a premium to guarantee the reliability of

their power, however, a manufacturing facility

may have sensitive equipment which requires

highly reliable power.

Value Per MWh ($)

MWhs


Benefit

Provided Low High Per Year Low High Assumptions & Comments:

Redundant

Power

Supply

(Reliability)

$3,900 $26,000 10 $39,000 $260,000

Assumes 4 outages of varying

lengths: 4 hours, 3 hours, 2 hours,

and 1 hour. Assume loading of

1MW during all outages.

MWhs per year:

= (4+3+2+1) h x 1 MW

= 10 MWh

Market

Arbitrage $13.90 $23.50 1460 $20,294 $34,310

It is assumed that the facility

discharges 4MWh on a daily

basis (which is 1MW discharged

for 4 hours) at peak electricity

rates (and charges accordingly at

off peak rates).

MWh per year:

= 4 MWh/day x 365 days

= 1460 MWh

Indirect

Benefits Low High Per Year Low High Assumptions & Comments:

Excess

Generation

Mitigation

$50.00 $116.09 1460 $73,000 $169,491 The battery will be charged at

night when excess generation

historically occurs in Ontario.

Greenhouse

Gas

Mitigation

$0.33 $6.69 1460 $482 $9,767

Charging at night when peaker

facilities are offline and

discharging during the day

reduces carbon emissions.

TOTAL

ANNUAL

BENEFIT:

$3,964.23 $26,146.28

$132,776 $473,569



34

Monthly Cost Per

MW/MWh ($)

MW/MWhs





Global Adjustment Charges $70.60 - $122.71 1460 MWh $139,636


Costs $60 $75 - $720 $900

Total Fixed Utility Charges $15,384.60 - - $15,384

TOTAL ANNUAL COST:

$251,589 $251,769





Distribution System





35








This case is not likely to be financially

viable unless market rules are changed to allow

project owners to monetize indirect benefits, or

if common costs can be lowered (or some

combination of both).

Case 5 – Behind Meter, GA Reduction

This case shows a unique opportunity for

Ontario consumers with an average annual

electricity demand of greater than 1MW. These

consumers all eligible for Class A status within

the province’s Industrial Conservation

Initiative (“ICI”). Class A customers have the

ability to reduce their Global Adjustment fees

by reducing their own demand during those

hours when Ontario’s electricity system is

experiencing its top five coincident demand

peaks in a given year. Therefore, in order to

achieve this benefit, a project must be located

behind the meter of a Class A customer. In

trying to achieve this goal, the project will

inherently be performing Market Arbitrage,


36

and will indirectly be mitigating excess

generation and have some Cap and Trade

value through reducing peak generation

requirements (assuming these peak

requirements are met using natural gas fired

generation facilities).

Analysis for this use case was performed

twice, once including demand charges

assuming that charging cycles for the energy

storage facility will increase peak demand

related to the customer’s load account, and

again assuming that demand charges can be

ignored, or charging cycles for the energy

storage facility will not increase peak demand

related to the customers load account. Other

charges, such as fixed utility costs, are not

considered because the customer would

reasonably be required to pay for these with or

without a storage project on site.

Benefit

Provided



Assumptions &

Comments: Low High Per Year Low High

Global

Adjustment

Charge

Reduction

(Class A)

$80,000 $105,000 5 $400,000 $525,000

The project will discharge

during all five Ontario

peaks, reducing the facility’s

demand by 1 MW each time.

Market

Arbitrage $13.90 $23.50 1460 $20,294 $34,310

This reflects the dollar

amount generated through

arbitrage on a daily basis.

MWh per year

= 365 cycles * 4 MWh

= 1460 MWh/year

Indirect

Benefits Low High Per Year Low High

Assumptions &

Comments:

Excess

Generation $50.00 $116.09 1460 $73,000 $169,491

The project will be charged

at night when excess

generation historically

occurs in Ontario.

Cap and

Trade

Benefit

$0.33 $6.69 1460 $482 $9,767

Charging at night when

peaker facilities are offline

and discharging during the

day reduces carbon

emissions.

TOTAL

ANNUAL

BENEFIT:

$80,064.23 $105,146.28 $493,776 $738,569



37

Monthly Cost Per

MW/MWh ($)

MW/MWhs



Total Demand Charges $7380 - 1 MW $88,549


TOTAL ANNUAL COST:

$95,849





Distribution System




The Demand charges in the table above are

included in Figure 6, but excluded in Figure 7.

As explained before in the exemptions to the

Demand charge barrier, if a storage project can

be charged and not increase the overall

demand for a facility Demand charges can be

ignored.


38

Figure 6: Present Value of Benefits and Costs - Case 5 with Demand Charges


scenario outlined by Case 5’s financial tables,

including Demand charges. A present value

has been determined net of common costs for a

15 year project life. To view a more detailed

chart with costs and revenues for each year, see

Appendix D.

As evidenced in the figure above, this case

is the most financially attractive hypothetical

scenario of all the analyzed use cases,

regardless of whether or not indirect benefits

can be monetized. Even when demand charges

are included, the calculated present value of

the project is positive, with the lower range

beginning at $3,379,610.42.


39

Figure 7: Present Value of Benefits and Costs - Case 5 without Demand Charges

This chart indicates the value of a project

that will not increase the peak demand for host

load customer (i.e. demand charges have been

removed from the common costs). When

compared with Figure 6, removing demand

charges results in an increase of $1,200,000 to

present value.


40

Conclusions

Under current market rules, regulations,

and legislation, three of the five presented use

cases could be economically viable, two of

those marginally. Generally, the closer to a

transformer station that a project is located, the

more benefits it has the potential to provide.

Based on the analyses of the range of use cases

sampled, the highest financial compensation

comes from those storage facilities located

behind the meter at Class A load sites, which is

contrary to what one might intuitively assume,

since there are more potential stacked benefits

that can be provided by locating closer to

transformer stations. The primary driver of this

counter intuitive finding is Global Adjustment

charges, and the ability for Class A consumers

to mitigate this cost through demand reduction

at key times. The effect of Global Adjustment

charges on energy storage project economics is

significant, and in some cases totaled more

than all other common costs combined.

Appendix E outlines how reducing GA costs

for energy storage system owners could be

justified and how a reduction would affect the

net present value of the first four use cases.

Suggestions on How to Monetize Indirect

Benefits

As discussed in this report, the identified

direct benefits are those benefits that are

currently monetizable. That is, a project owner

could be compensated for providing these

identified benefits under the current market

framework.

However, for indirect benefits,

fundamental changes in market rules would be

required to provide monetary compensation to

project owners. Below is a table of currently

non-monetizable (or indirect) benefits.


41

Theoretically

Monetizable

Benefits

Monetary Range

(per MWh of

services

provided)

Description

Excess

Generation

Mitigation

$50.00 - $116.09

Charging storage units during excess generation conditions, in the

province, rather than exporting surplus at a loss. Upper limit

assumes all charging is accomplished under excess generation

conditions, the lower limit assumes that some charging is done under

excess generation conditions.

Greenhouse Gas

Mitigation (Cap-

and Trade)

$0.33 - $6.69

Value associated with reducing CO2 emissions by offsetting natural

gas facilities with non-CO2 emitting energy storage resources. Values

derived using cap-and-trade projections. The high end of the value

range assumes the energy storage facility is discharging at a time

when it is completely offsetting CO2 emitting generation in the

province and charging when there is essentially zero CO2 emission

generation in the province. The lower end of the value range involves

scenarios that are less than this ideal state (i.e. some charging occurs

while CO2 emitting power generation is online and not 100% of the

discharging is necessarily offsetting CO2 emitting generation).

Enables Higher

Penetration of

Renewables

$90 - $130 Value associated with reducing curtailment of wind resources in

Ontario as a result of dispatching storage resources.

Table 24: Indirect Benefit Value Matrix

The following is a list of suggestions related to

how indirect benefits might be made

monetizable in Ontario.

Excess Generation Mitigation

Quantify the value that the province

saves by reducing the export of

electricity during periods of excess

generation and redirect a portion of

these funds to the purveyor of a storage

project (through a PPA or other new

market mechanism). The long term goal

would be to commission enough energy

storage facilities to store all excess

energy during excess generation

conditions within the province.

Greenhouse Gas Mitigation

As more storage projects come to

fruition, the operation of gas fired

generators, including peaker plants, can

be minimized.

Reducing CO2 emissions related to gas

fired generation has a market value as

determined by Ontario’s Cap and Trade

program. Revenues resulting from this

program (which flow to the province’s

Green Investment Fund) could be

diverted to energy storage projects to

recognize their contribution to

emissions reductions in certain

applications.


42

Enables Higher Penetration of Renewables

Currently, when renewable generators

have capacity to produce more

electricity than the

distribution/transmission system can

technically manage, they are curtailed.

Curtailment means that a generator had

the ability to generate, but was

constrained to shut down. Generally,

there are commercial limits to the

magnitude of curtailment (determined

through PPAs). Renewable generators

generally receive a form of

compensation when these limits are

exceeded based on their potential to

produce at the time of curtailment.

The proposed value provided by

storage facilities is derived from storing

energy (that would have otherwise been

curtailed) for later use. Instead of

curtailment, the proposed solution

would be to compensate a project owner

for storing the energy and releasing it

when it is technically required and

provides more value to the system.

Tools Available to Address Identified Barriers

Below is a list of tools and suggestions

which could mitigate or remove some of the

barriers identified throughout this report.

Studying more mature energy markets to

glean best practices to mitigate concerns

of lenders and insurers in regards to new

technology.

Leverage documentation in existing

Technical Interconnection Requirements

for connection standards in Ontario, but

revise them to be applicable to energy

storage.

Power Purchase Agreements are an

existing framework that could be used for

storage projects in order to compensate

owners for indirect benefits provided.

Depending on the type of project,

location, and other factors, projects could

require a variety of permits and

approvals before development can begin.

A list of the potential permits and

approvals that may be required can be

found at

http://canadabusiness.ca/permits-and-

licences/.

Where indirect benefits are confirmed

and measurable but cannot be monetized

directly, one option may be to apply

lower Demand Charges to merchant

energy storage projects in

acknowledgement of non-monetizable

benefits.

Given that stored energy is expected to be

re-injected to the distribution system, it

may be a consideration for energy storage

system owners to pay GA only on the

portion of energy that is not re-injected

back to the grid (i.e. losses). See

Appendix E for a GA financial flow chart

which demonstrates implementing this

suggestion does not result in any other

load customers paying additional GA on

behalf of energy storage facilities. The

amount of GA payable upon charge and

discharge may not be equal if a

significant amount of time has passed. A

settlement mechanism to account for

these differences may be required.

Develop a fair, practical, and consistent

compensation and cost for transfer trip

substation installation upgrades given

that the first to install a project generally

incurs most cost, while subsequent

projects rarely incur comparable costs,

http://canadabusiness.ca/permits-and-licences/

http://canadabusiness.ca/permits-and-licences/


43

nor do they compensate the initial project

developer.

Create standards for production, design,

installation, and maintaining energy

storage projects by appropriate societies

and organizations for peer review (i.e.

IEEE, TSSA, CSA, UL, etc.).

Develop an aggregation archetype so that

numerous, disparate energy storage

systems can be amalgamated into a single

virtual storage facility and controlled

accordingly. Aggregation technology

currently exists for demand response, but

it is uncertain if a suitable Ontario

market-proven, bi-directional

aggregation solution for regional storage

exists.

Establish a clearer framework within the

OEB rate setting process that more

readily enables LDCs to rate base storage

assets that demonstrate cost effective

benefits to end use rate payers. To be

most effective, the framework would

require common tool sets and a process

for LDCs to adopt and apply in order to

consistently assess a multitude of

potential use cases. Based on benefits

provided by energy storage, LDCs may

often be ideal owners for distribution

connected systems, particularly when

directly connected.

Top Three Scenarios

Given the use cases, benefit values,

barriers, and tools available to the province that

are presented in this study, this section

summarizes three scenarios that would benefit

the development of distribution connected

energy storage over the next one to ten years.

These scenarios generally aim to reasonably

reduce common costs and convert indirect

benefits to direct benefits for energy storage

project owners, while still benefitting rate

payers in Ontario.

Scenario 1 – Global Adjustment Reduction

As illustrated in the use cases 1 through 4

of this study, Global Adjustment charges are

detrimental to the financial business cases for

Class B merchant energy storage developers.

The fifth use case is profitable largely because it

reduces GA charges for the Class A load

customer. Administering GA charges such that

they apply only to losses (energy consumed by

the storage facility minus energy discharged)

has the potential to cut common costs by over

half. This single change in settlement would

greatly accelerate economic viability of

merchant storage projects. See Appendix E for

how a reduction in GA costs would affect the

first four use cases.

Scenario 2 – Enabling Renewable Generation

Case 2 outlines the savings potential of

reducing renewable curtailment. As previously

mentioned, storing energy which would have

been curtailed and then releasing energy when

it is needed can reduce costs associated

generation that are currently reflected in Global

Adjustment. Passing a portion of this savings to

developers of integrated renewable energy /

storage facilities (through a PPA or other

market mechanism) may result in more

economically viable storage projects.

Scenario 3 – Excess Generation Mitigation

It is an intuitive benefit of energy storage

to store excess generation for later use. Many of

the use cases in this study demonstrate the


44

indirect benefit of excess generation mitigation,

which has become a social and economic

concern to Ontario ratepayers. Enabling storage

project owners to share in the savings realized

when providing this mitigation, and thus

reduce the overall impact, could help ease these

concerns.


45

Appendix A

Value Matrix

All values provided in the Value Matrix are normalized to dollars per megawatt-hour

($/MWh) of electricity delivered to the grid. The Value Matrix is intended to present the

potential value of the individual benefits for a given deployment of energy storage, whether

theoretical or currently monetizable. The benefits and associated values are defined and derived

such that no overlapping exists from one benefit to another – that is, they truly stack when they

are applicable to a given application. It is incumbent on the energy storage system developer to

determine the applicable benefits and possible MWhs delivered in a particular case.

Benefits

Monetary

Range (per

MWh of

services

provided)

Description

Market Arbitrage $13.90 -$23.50 Value that could be derived strictly through purchasing

energy at a low cost and selling at a high cost, using

Ontario's market price signals.

Distribution System

Upgrade Avoidance $12.87 -$133.56

Value of avoiding distribution system upgrades as a result of

dispatching energy storage. For example, congestion

mitigation may lead to avoidance of feeder expansion.

New Generation

Capacity Avoidance $12.15 -$25.23

Value of using stored energy to reduce demand on the

distribution system such that the development of new

generation facilities is avoided.

Redundant Power

Supply (Reliability) $3,900 -$26,000

Value of using stored energy to provide power to loads

during traditional distribution system outages. The lower

end of the range typically represents residential load and the

higher end of the range represents commercial, industrial, or

load of a critical nature.

Non-Spinning Reserve

Availability $0.20 - $30

Value paid to resources that participate as a part of "Non-

Spinning Reserve", or generation capacity which can inject

power after a short delay.

Spinning Reserve

Availability $0.20 - $54

Value paid to resources that participate as a part of

"Spinning Reserve", or generation capacity which can inject

power immediately.

Reserve Activation $0.40 - $135 Value paid to resources that participate as a part of

"Spinning Reserve" programs, once activated for supplying

reserve.

Power Quality

Improvement $6.06 -$11.35

Value of using energy storage to improve the quality of

power delivered to customers.

Frequency Regulation $45 - $65 Value of dispatching energy storage to provide Frequency

Regulation for IESO.

Voltage Control $8.30 -$58.50 Value of dispatching energy storage to provide Voltage

Control for IESO.

Black Start $5.85 - $36 Value of dispatching energy storage to provide Black Start

services IESO.


46

Reduced Dispatching

of Peaker Facilities $110 - $170

Value of dispatching energy storage facilities as peaker

facilities in Ontario to meet peak demand, assist in ramping,

and assist with load following. Peaker facilities were

assumed to be natural gas facilities, therefore they are

sensitive to natural gas prices in Ontario.

Global Adjustment

Charge Reduction

(Class A)

$80,000 -

$105,000

Value of reducing consumption during all five Ontario

coincident peaks by 1 MW.

Theoretically

Monetizable Benefits

Monetary

Range Description

Excess Generation

Mitigation $50.00 -$116.09

Charging storage units during excess generation conditions

(provincially) rather than exporting surplus at a loss. Upper

limit assumes all charging is accomplished under excess

generation conditions, and the lower limit assumes that some

charging is done under excess generation conditions.

Greenhouse Gas

Mitigation (Cap-and

Trade)

$0.33 -$6.69

Value associated with reducing CO2 emissions by offsetting

natural gas facilities with non- CO2 emitting energy storage

resources. Values derived using cap-and-trade projections.

The high end of the value range assumes the energy storage

facility is discharging at a time when it is completely

offsetting CO2 emitting generation in the province and

charging when there is essentially zero CO2 emission

generation in the province. The lower end of the value range

involves scenarios that are less than this ideal state (i.e. Some

charging occurs while CO2 emitting power generation is

online and not 100% of the discharging is necessarily

offsetting CO2 emitting generation).

Enables Higher

Penetration of

Renewables

$90 - $130 Value associated with reducing curtailment of resources in

Ontario as a result of dispatching storage resources.


47

Benefit Matrix

The four most likely locations where an energy storage system might be utilized include: i)

at the transformer station, ii) in the middle of the feeder, iii) at the end of the feeder, or iv)

behind the meter. Colour coded symbols indicate the relative viability of energy storage

providing a specific benefit at a particular location. A green check mark indicates that an energy

storage system is suitable to provide the associated benefit at the particular location. A yellow

check mark indicates that an energy storage system is somewhat suitable to provide the

associated benefit at the particular location. A red “X” indicates that an energy storage system is

unlikely or otherwise unable to provide the associated benefit at the particular location.

Distribution Connected Energy Storage Location4

Currently Monetizable Benefits At TS Middle of

Feeder

End of

Feeder

Behind

Meter

Market Arbitrage

Distribution System Upgrade Avoidance

New Generation Capacity Avoidance

Redundant Power Supply (Reliability)

Non-Spinning Reserve Availability

Spinning Reserve Availability

Reserve Activation

Power Quality Improvement

Frequency Regulation

Voltage Control

Black Start

Reduce Dispatching of Peaker Facilities

Global Adjustment Charge Reduction (Class A)

4 Some benefits may be viable at other locations if an aggregator could be used. For simplicity this

assessment only considers single connections.


48

Theoretically Monetizable Benefits At TS Middle of

Feeder End of

Feeder Behind

Meter Excess Generation Mitigation

Greenhouse Gas Mitigation (Cap-and Trade)

Enables Higher Penetration of Renewables


49

Appendix B

Benefit Calculation Methodology

Assumptions for all calculations:

Benefits provided by energy storage facilities are highly dependent on the individual

circumstances of each application; therefore, a range of values has been developed to

accommodate a variety of typical projects. While the ranges, based on research, capture

the value of the benefits experienced for the majority of energy storage projects, it is

possible that applications exist where values extend beyond those provided herein.

Where benefit values are clearly linked to the Ontario energy sector, Ontario market

data as well as other regional sources were used to derive Ontario-specific ranges.

Where benefit values are more universal, multiple sources across multiple jurisdictions

were cross-checked and used to derive ranges.

All dollars are expressed as $/MWh Canadian for services delivered to the grid

Canadian exchange rate was assumed to be $1.30 from US currency where applicable

1. Market Arbitrage ($13.90 - $23.50)

Assumed a four hour charge cycle and four hour discharge cycle

Summed the Hourly Ontario Electricity Price (HOEP) for each day in a month to find the

total monthly price for a single hour [17]

Calculated the lowest HOEP total for a consecutive four hour period for each month to

determine charge periods

Calculated the highest HOEP total for a consecutive four hour period for each month to

determine discharge periods

Calculated the average profit made from charging at the lowest rate and discharging at

the highest rate for 2011 – 2016, and divided by four to get the price per hour

Lowest profit margin occurred during 2012 ($13.93), highest profit margin occurred

during 2014 ($23.43). Upper and lower limits were approximated with these values.

2. Distribution System Upgrade Avoidance ($12.87 - $133.56)

The benefit value upper and lower limits, in $/kW-year, were determined by considering

several research papers [18], [19], [20], [21]

The following formula was used to convert $/kW-yr to $/MWh

$/𝑀𝑊ℎ = (𝑉𝑎𝑙𝑢𝑒 𝑖𝑛 $

𝑘𝑊⁄ 𝑦𝑒𝑎𝑟) ∙ 1000 𝑘𝑊/𝑀𝑊

𝑇𝑜𝑡𝑎𝑙 𝐷𝑢𝑟𝑎𝑡𝑖𝑜𝑛


50

$/𝑀𝑊ℎ = 112.8 $

𝑘𝑊⁄ 𝑦𝑒𝑎𝑟 ∙ 1000 𝑘𝑊/𝑀𝑊

8760 ℎ𝑦𝑒𝑎𝑟⁄

= $ 12.87/𝑀𝑊ℎ (𝑀𝑖𝑛𝑖𝑚𝑢𝑚)

$/𝑀𝑊ℎ = 1170 $



= $ 133.56/𝑀𝑊ℎ (𝑀𝑎𝑥𝑖𝑚𝑢𝑚)

3. New Generation Capacity Avoidance ($12.15 - $25.23)

The benefit value upper and lower limits, in $/kW-year, were determined by considering

several research papers [2], [19], [4], [5]

The following formula was used to convert $/kW-yr to $/MWh

$/𝑀𝑊ℎ = (𝑉𝑎𝑙𝑢𝑒 𝑖𝑛 $

𝑘𝑊⁄ 𝑦𝑒𝑎𝑟) ∙ 1000 𝑘𝑊/𝑀𝑊

𝑇𝑜𝑡𝑎𝑙 𝐷𝑢𝑟𝑎𝑡𝑖𝑜𝑛

$/𝑀𝑊ℎ = 106.8 $



= $ 12.15/𝑀𝑊ℎ (𝑀𝑖𝑛𝑖𝑚𝑢𝑚)

$/𝑀𝑊ℎ = 221 $



= $25.23/𝑀𝑊ℎ (𝑀𝑎𝑥𝑖𝑚𝑢𝑚)

4. Redundant Power Supply ($3,900 - $26,000)

The value of a redundant power supply is highly dependent on the load it services.

Despite the wide range derived for this benefit, it is conceivable there are projects that

may extend beyond this range.

The benefit value upper and lower limits in $/MWh for Redundant Power Supply were

determined by considering a research paper [3]

5. Non-Spinning Reserve Availability ($0.20 - $30)

Source data is IESO Data Directory [22], [23]

Removed upper and lower outliers (top and bottom 1%, around 100 data points total)

from market data from 2002-2016


51

Figure 8: Distribution of Non-Spinning Operating Reserve Market Price

6. Spinning Reserve Availability ($0.20 - $54)


Removed upper and lower outliers (top and bottom 1%, around 100 data points total)

from market data from 2002-2016

Figure 9: Distribution of Spinning Operating Reserve Market Price

0

500

1000

1500

2000

2500

3000

3500

4000

4500

$0 $5 $10 $15 $20 $25 $30 $35 $40

Fre

qu

en

cy o

f M

arke

t P

rice

Market Price

10 Minute Non-Spinning Price 2002-2016

0

500

1000

1500

2000

2500

3000

3500

4000

4500

$0 $5 $10 $15 $20 $25 $30 $35 $40

Fre

qu

en

cy o

f M

arke

t P

rice

s

Market Price

10 Minute Spinning Reserve Prices 2002-2016


52

7. Reserve Activation ($0.40 - $135)


Considered only positive HOEP prices, upper limit is average HOEP ($40.10) plus three

standard deviations (one standard deviation being $33.62)

Figure 10: Distribution of HOEP Market Price

8. Power Quality Improvement ($6.06 - $11.35)

The benefit value upper and lower limits, in $/MWh, were determined by considering a

research paper [2]

9. Frequency Regulation ($45 - $65)

Referenced the total amount spent by IESO for frequency regulation in 2015

($45,150,514.04) and calculated the average amount spent per hour [26]

Then divided by average amount of scheduled regulation per hour (±100 MW)

$45,150,514.04/𝑦𝑒𝑎𝑟

8760 ℎ

𝑦𝑒𝑎𝑟

= $5154/ℎ

$5154/ℎ

100 𝑀𝑊= $51.54/𝑀𝑊ℎ

Confirmed with other research studies and established an upper and lower bound using

other sources [4], [27]

10. Voltage Control ($8.30 - $58.50)

IESO sources provided total amount spent in 2015 for Voltage Control ($20,018,689.52)

0

10000

20000

30000

40000

50000

60000

70000

80000

-$20 $0 $20 $40 $60 $80 $100 $120 $140

Fre

qu

en

cy o

f M

arke

t P

rice

HOEP

HOEP for 2002-2016


53

[26]

Supplemented with proxy data from other research papers [4], [5]

11. Black Start ($5.85 - $36)

IESO sources provided total amount spent in 2015 for Black Start Services ($1,410,114.36)

[26]

Supplemented with proxy data from another research paper [5]

12. Reduced Dispatch of Peaker Facilities ($110 - $170)

In lieu of confidential agreements, used OEB’s Regulated Price Plan report to determine

amount paid to generation facilities when dispatched [28]

Does not include compensation for peaker plants being on standby

Expanded upper and lower limits to allow for changing natural gas prices

13. Global Adjustment Charge Reduction (Class A) ($80,000 -$105,000)

The table below indicates the total adjusted megawatts for each peak in 2015, and what

the coincident peak factor would be for a 1 MW reduction

Date Hour

Ending

Demand

Reduction

(kW)

Total

(MW)

Adjusted Quantity of

Energy Withdrawal

(MW)

Coincident Peak

Factor (CPF)

July 28, 2015 17 1,000 23,024 22,016 0.00004542

July 29, 2015 17 1,000 22,835 21,900 0.00004566

Aug. 17, 2015 17 1,000 22,892 21,882 0.00004570

July 27, 2015 18 1,000 22,323 21,562 0.00004638

Sept. 3, 2015 14 1,000 22,860 21,429 0.00004667

Total

5,000 113,935 108,788 0.00004388

Forecast Annual Total GA (M): $11,836.50

Table 25: Five Coincident Ontario Peaks for 2015

To find the total amount saved in one year by reducing demand by 1 MW on each peak,

multiply the average CPF by the Annual Total GA

𝐴𝑛𝑛𝑢𝑎𝑙 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 = 𝐶𝑃𝐹 ∙ 𝐴𝑛𝑛𝑢𝑎𝑙 𝑇𝑜𝑡𝑎𝑙 𝐺𝐴

𝐴𝑛𝑛𝑢𝑎𝑙 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 = 0.00004667 ∙ $11,836,500,000

𝐴𝑛𝑛𝑢𝑎𝑙 𝑆𝑎𝑣𝑖𝑛𝑔𝑠 = $552,409.46

The annual savings was averaged over five peaks and a margin of error applied for

upper and lower limits


54

14. Excess Generation Mitigation ($50 - $116.09)

The value of mitigating excess generation in Ontario is derived by comparing the

average cost associated with producing power in Ontario with the average price (HOEP)

that power is exported at during times of excess generation in the province.

Average HOEP when exporting power during in June 2015 (used as sample) was $15.31

(which does not include Global Adjustment – additional costs associated with

generation in Ontario) [29], [25]

Average actual cost to produce power during the same period in Ontario was $131.40

(which includes Global Adjustment) [17], [25]

Therefore, upper limit of this value of Ontario’s mitigated excess generation is set to

$131.40 - $15.31 = $116.09

Lower limit set to $50 to establish a reasonable range. It is acknowledged that the low

end of the range could vary depending on timing of an energy storage facility (i.e. time-

of-day charging and discharging).

15. Greenhouse Gas Mitigation ($0.33 - $6.69)

This benefit assigns a market-based value to the CO2 emissions that are avoided when

storage offsets CO2 emitting sources. A similar amount is not accounted for within PPA-

related payments to carbon emitting generators in this study, there is no overlap of this

indirect benefit with other direct or indirect benefits described herein.

Calculated pounds CO2/kWh for a combined cycle natural gas generator [30], [31]

116.999 𝑙𝑏𝑠𝐶𝑂2

𝑀𝐵𝑡𝑢⁄ × 7658 𝐵𝑡𝑢𝑘𝑊ℎ⁄

1000000𝐵𝑡𝑢/𝑀𝐵𝑡𝑢 = 0.8959783 𝑙𝑏𝑠𝐶𝑂2/𝑘𝑊ℎ

Converted to kilograms CO2/MWh

0.8959783𝑙𝑏𝑠𝐶𝑂2

𝑘𝑊ℎ⁄ × 0.45359237

𝑘𝑔𝑙𝑏

⁄ × 1000 𝑘𝑊ℎ𝑀𝑊ℎ⁄ = 406.4089 𝑘𝑔𝐶𝑂2/𝑀𝑊ℎ

Based on current California-Quebec Cap-and-Trade auction results, cost per metric

tonne of CO2 used for the calculation of this benefit is $16.45/tonne [32], [33]

Upper Limit:

Assuming 100% of 1 MWh natural gas generation is offset during discharge and 100% of

the supply mix during charging does not emit CO2:

406.409 𝑘𝑔𝐶𝑂2

𝑀𝑊ℎ⁄ × $16.45/𝑡𝑜𝑛𝑛𝑒

1000𝑘𝑔

𝑡𝑜𝑛𝑛𝑒⁄= $6.69 /𝑀𝑊ℎ


55

Lower Limit:

Calculated the difference between the sum of the minimum and maximum CO2

emissions (kg) produced in order to generate energy for four hour continuous periods

(within a given day), based on Ontario’s actual supply mix, using market data over 270

days in 2016 [17]. This difference is 21.509 tonnes.

21.509 tonnes is converted to a dollar value per MWh by multiplying it by the price per

tonne assigned to CO2 ($16.45/tonne of CO2, from above) and dividing by the number of

hours of discharge (4 hours per day, 270 days), yielding a low limit result of $0.33 per

MWh.

It is acknowledged that this low end of the range itself could vary depending on the

timing of the application of the energy storage facility and the resulting fuel source

mixes during charge and discharge cycles.

16. Enabling Higher Penetration of Renewables ($90 - $130)

Used OEB’s Regulated Price Plan report to find amount paid to wind generators [28]

Found lower limit by an assumed efficiency factor for storage losses (70%)

Upper limit was established using a minimal amount for allowable curtailment


56

Appendix C Several permit costs are dependent on the size of a project, where this is the case the

upper limit will indicate “Size”.

Permit Type Jurisdiction Permit Name Low

Cost

High

Cost

Environmental Federal Approval under Navigable Waters

Protection Act

$ - $ -

Environmental Federal Migratory Game Bird Hunting Permit $ 17 $ 17

Environmental Federal Species At Risk Permit $ - $ -

Land Use Federal Application for Federal Crown Land $ 159 $ 159

Land Use Federal Land Use Proposal $ - $ -

Road Work Federal Notice of work close to railways $ - $ -

Sewer/ Water Federal Aeronautical Obstruction Clearance Permit $ - $ -

Construction Provincial Building and Land-Use Permit $ 90 Size

Construction Provincial Development Permit Application - NEC-4 $ - $ -

Construction Provincial Electrical Permit (Application for

Inspection)

$ 79 Size

Construction Provincial Electricity Transmitter Licence $ 60 $ 60

Environmental Provincial Vegetation Control Permit $130.81 $130.81

Land Use Provincial Application to amend The Niagara

Escarpment Plan

$ - $ -

Road Work Provincial Encroachment Permit $ 520 $ 1,560

Road Work Provincial Highway Building and Land Use Permit -

Building and Land Use Permit / Entrance

Permit

$ 195 Size

Road Work Provincial Oversize/Overweight Permit $ 65 $ 700

Construction Municipal Building Permit $ 90 Size

Construction Municipal Building Permit - Large Sign Permit $ 225 $ 225

Construction Municipal Demolition Permit $ 90 $10,000

Construction Municipal Heating, Ventilation and Air Conditioning

(HVAC) Permit

$194.24 $349.62

Environmental Municipal ChemTRAC $ - $ -

Environmental Municipal Tree Conservation $ - $ -

Land Use Municipal Crown Shore Allowance Release Request $ 500 $ 500

Land Use Municipal Moving Permit $ 50 $ 50

Land Use Municipal Occupancy Permit $ 10 $ 10

Land Use Municipal Planning and Zoning Requirements $ 80.31 Size

Road Work Municipal Culverts/Driveways $ 1,450 Size

Road Work Municipal Curb Cut Permit $ 8 $ 8

Road Work Municipal Permanent Encroachment Permit $ 34 Size


57

Road Work Municipal Private Approach Permit $ 149 $ 661

Road Work Municipal Road Closure Authorization $ - $ -

Road Work Municipal Road Cut Permit $337.75 $337.75

Road Work Municipal Single Trip Oversize Load Permit $ 28.92 $ 28.92

Road Work Municipal Temporary Encroachment Permit $ 28.50 Size

Road Work Municipal Temporary Street Occupation Permit $ 47.38 Size

Sewer/ Water Municipal Application for Supply of Bulk Water $ 2.21 $ 2.21

Sewer/ Water Municipal Building Retrofit Water and/or Sewer

Service Connections

$ 639 Size

Sewer/ Water Municipal Drain Site Services Permit $ - $ -

Sewer/ Water Municipal Plumbing Permit $ 10 $ 10

Sewer/ Water Municipal Sewer/Septic Permit $ 130 $ 1,000

Sewer/ Water Municipal Water Connection/Disconnection Permit $ 50 Size

Table 26: Permit Type and Possible Cost


58

Appendix D

Figure 11: Case 1 – 15 Year Project Life Cost and Benefit Chart


59



60



61



62

Figure 15: Case 5 (Demand Included) – 15 Year Project Life Cost and Benefit Chart


63

Figure 16: Case 5 (Demand Not Included) – 15 Year Project Life Cost and Benefit Chart


64

Appendix E

This appendix demonstrates the cash flows that could occur during charge and

discharge cycles in the Ontario market given a purely merchant scenario for an energy storage

facility. It appears there may be an imbalance in the amounts paid to the IESO and the amounts

paid by the IESO, due to the settlement of GA.

Figure 17 depicts a very simplistic representation of the basic flow of cash through the

Ontario electricity market without consideration for energy storage.

Figure 17: Conventional cash flow, Ontario market

The IESO administers and settles the electricity market, ultimately collecting money

from customers to distribute payments to generators. In the example shown in the figure above,

payment for 1 MWh (HOEP and GA) passes from the customer to the IESO, and the IESO

distributes payments at a contracted price to the generator(s) that produced the electricity.

Essentially, the difference between contract and related payments to generators/suppliers and

HOEP is the primary driver for GA charges, so if contracted prices are close to HOEP then GA

becomes less significant. While historically this has generally not been the case, there have been

Customer

1 MWh

1 M

Wh

of

Co

ntr

ac

ted

Pric

e

1M

Wh

of H

OEP

an

d G

A

Generator

IESO

Cash Flow – Ontario Market, No Storage

Generator

Energy flow through the grid


65

instances where GA has become negative to distribute an over-collection of funds back to the

customers.

In Figure 18, the cash flow diagram considers an energy storage facility during a

charging cycle. For demonstration purposes, the storage system is assumed to have an 80%

efficiency rating between its charge and discharge cycles, thus, it consumes 1.25 MWh of energy

to enable a discharge of 1 MWh of energy.

Figure 18: Cash flow in the Ontario market considering an energy storage charge cycle

In this scenario, a generator is required to deliver 1.25 MWh of energy to the broader

electricity grid (where storage is connected) in order to charge the storage facility. The generator

is then compensated by the IESO for its energy production and the storage facility must pay the

IESO for 1.25 MWh of HOEP and GA for the energy it consumed while charging.

Figure 19 illustrates the cash flows that would be expected to occur when a storage

facility discharges, thus delivering energy to the grid to ultimately support customer load.

Storage

1.25 MWh

1.2

5 M

Wh

of

Co

ntr

ac

ted

Pric

e

1.2

5 M

Wh

of H

OEP

an

d G

A

Generator

IESO

Cash Flow – Storage, Charge Cycle



66

Figure 19: Cash flow in the Ontario market considering an energy storage discharge cycle

When the storage facility discharges to the grid in order to deliver a customer 1 MWh of

energy, the storage facility is compensated for 1 MWh at HOEP rates (without GA) by the IESO.

Also, as in Figure 17, the customer consumes 1 MWh of energy and pays the IESO (directly or

indirectly depending on wholesale/retail status) HOEP and GA accordingly.

This scenario appears to leave an imbalance in the cash flows at the IESO level. That is,

the IESO collects for a total of 2.25 MWh of HOEP and GA charges, while paying out for 1.25

MWh of contracted price and 1 MWh of HOEP (no GA). In other words, in the charging

scenario, the IESO collects GA from the storage facility and uses it to pay generators. In the

discharging scenario, the IESO collects GA from the load customer, but is not required to use

this GA to compensate generators, since it already did this when the storage facility was

charging. Figure 20 graphically illustrates this potential imbalance.

Customer

1 MWh

1 M

Wh

of

Co

ntr

ac

ted

Pric

e

1M

Wh

of H

OEP

an

d G

A

Storage

IESO

Cash Flow – Storage, Discharge Cycle



67

Figure 20: Imbalance of HOEP and GA Payments

The following are alternative scenarios conducted during the course of this study. These

scenarios were created in order to more clearly show the effect that Global Adjustment charges

have on the original scenario models. Four of the five original use cases (i.e. Use Cases 1 - 4) are

included in this appendix; the fifth use case is not included here since the original use case is

based upon Global Adjustment savings for a Class A customer.

For each scenario presented below, the original net present value is presented on the left,

with the measure for the alternative scenario (i.e. 20% Global Adjustment) on the right. For each

scenario, only the Global Adjustment charges have been reduced to offset the imbalance

described in this appendix in order to produce “what if GA was balanced” use cases. All other

parameters for each scenario remain the same as in the original case.

Paid by IESO Paid to IESO

≈

≠


68

Figure 21: Case 1 – Original Scenario and 20% GA Scenario



69




70

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