Total Value Model (TVM) - Innovari · Innovari has developed a Total Value Model (TVM) to enable a...

@2013 Innovari, Inc. All Rights Reserved

Total Value Model (TVM)

Estimating the value of Grid Optimization with the Interactive Energy Solution™

September 2013

Innovari, Inc. 2900 N Quinlan Park Rd Suite B240, #215 Austin, TX 78732 www.innovari.com

Confidential and Proprietary

TableofContents

EXECUTIVE SUMMARY .............................................................................................................................. 1

INTRODUCTION ......................................................................................................................................... 1

GENERAL INPUTS ...................................................................................................................................... 4

GENERATOR DEFERRAL ............................................................................................................................. 5

ENERGY SALES ........................................................................................................................................... 7

RETURN ON ASSETS .................................................................................................................................. 9

FEEDER DEFERRAL ................................................................................................................................... 11

ANCILLARY SERVICES ............................................................................................................................... 13

LOST REVENUE RECOVERY ...................................................................................................................... 14

ENVIRONMENTAL BENEFITS ................................................................................................................... 15

BMS ENERGY EFFICIENCY SAVINGS ......................................................................................................... 17

SYSTEM LOSS SAVINGS ........................................................................................................................... 19

SUBSTATION DEFERRAL .......................................................................................................................... 20

OUTAGE & RESTORATION ....................................................................................................................... 21

GLOSSARY ................................................................................................................................................ 22

© 2013 Innovari, Inc. All Rights Reserved ‐‐ Page 1 of 23

EXECUTIVE SUMMARY

Each utility has different country, regional, organizational, and regulatory differences that affect both

deployment parameters and the value resulting from a deployment. Innovari has developed a Total

Value Model (TVM) to enable a utility to customize their evaluation of a deployment of Innovari’s

Interactive Energy Solution™ (IES) and quantify the following associated value streams:

Generator Deferral,

Energy Sales,

Return on Assets,

Feeder Deferral,

Ancillary Services,

Lost Revenue Recovery,

Environmental CO2e Reduction,

BMS Energy Efficiency Savings,

System Loss Savings,

Substation Deferral, and

Outage & Restoration. This document is designed to be a companion document to the TVM Workbook (a MS Excel file) that

allows each utility to input their own parameters and determine which value streams are most

applicable for their systems.

INTRODUCTION

The TVM is built on a MS Excel Workbook. The TVM Workbook consists of:

several high‐level worksheets which summarize and display the results as well as provide a place to enter common inputs (Figure 1), and

worksheets specific to each value driver (Figure 4).

Worksheet Description

Summary Lists the benefits from each individual value driver in one place and provides the

ability to include or exclude each value driver from the summary calculation. The

annual benefits and the net present value (NPV) of each of the value streams are

shown. In addition, the project’s “net value” is shown by deducting the initial and

recurring project costs from the aggregation of the net present values created.

(Figure 2)

Value Waterfall Based on user inputs, provides a graph of the NPV of each value driver, the NPV of

the initial and recurring costs and the total net value of the project. (Figure 3)

General Inputs Combines assumptions that span multiple value drivers into one place such as

capacity, inflation rates, and other cross‐model assumptions. Value driver specific

assumptions are included on the individual value driver worksheets described in

Table 2.

Figure 1. Description of First Three Worksheets in TVM Workbook


Figure 2. Illustration of the Summary Worksheet

Figure 3. Illustration of the Value Waterfall Worksheet

62

37

22 15

9 10 6 4 3 2 0.1 171

90

81

Net Value Benefit$ MM


Value Driver Description

Generator Deferral The value from deferring capital investments in peaking power generation

plant capacity but not including the associated environmental benefits (see

Environmental Benefits below)

Energy Sales The value of the potential wholesale market sales of the guaranteed energy

reduction that is available

Return on Assets The value of the return on the asset at the allowed rate of return that the

utility can earn on the project as a plant‐in‐service asset

Feeder Deferral The value from targeted deployment and resulting deferral of capital

investment in feeder upgrades by reducing or balancing the peak load on

those feeders.

Ancillary Services The value from using the project as part of the utility’s ancillary services

portfolio

Lost Revenue Recovery The recovery of “lost” revenue allowed in some jurisdictions to compensate

for the energy savings realized by the end‐use customer

Environmental Benefits The value of environmental benefits such as CO2e reductions that result

from the reduction in energy generation

BMS Energy Efficiency

Savings

The value of the energy savings realized by buildings that do not have a

building management system (BMS), for utilities with energy efficiency

incentives in place

System Loss Savings The value of the energy savings as a result of decreased system losses on

the grid for demand side management projects

Substation Deferral The value from targeted deployment and resulting deferral of substation

upgrades by reducing peak load on those substations

Outage & Restoration The value from last‐gasp capabilities to identify outages, increasing

restoration efficiency and mitigating unnecessary crew site visits

Figure 4. Value Driver Worksheets in the TVM Workbook

The following sections describe the General Input Worksheet and each of the Value Driver Worksheets

in the TVM Workbook in more detail.


GENERAL INPUTS

OverviewThe TVM Workbook uses this single worksheet to enter and adjust all common inputs for the entire

model. In this way, the user can run scenario analyses across the entire workbook with single

adjustments of the common variables.

ValueComponents Project Attributes

• Contract Capacity • Deployment size and durations • Installation cost ($/kW) • O&M cost ($/kW‐yr) • Customer incentives • Assumed service life of the project

Equity structure of the utility (default is industry standard)

• % Equity • Equity Rate • Debt Rate • WACC

Duration of Debt repayments

Tax rates

Inflation rates

ApproachThe values on this General Input Worksheet are used through the balance of the workbook and can

identified in “black” text whereas additional input requirements for each worksheet are found in “blue”

text. As with any Excel workbook, the user can mouse over any cell to find the embedded calculation,

input values or source locations of data. The workbook is formatted to automatically update upon every

data entry or change.


GENERATOR DEFERRAL

OverviewThe Innovari IES provides the opportunity to defer capital investments in peaking power generation

capacity and associated operating costs. By actively managing demand, the need for generation

production can be deferred or potentially eliminated.

ValueComponents Installation Costs

• Deferred Generator Size • Deferred Generator Installation Cost ($/ kW)

Operating Costs (Opex)

• Fixed • Variable (Fuel)

Deferral Timeline and Duration

ApproachFirst, a given generator capacity is assumed (e.g., 50 MW) as the basis for the calculations. Then an

installation cost assumption can be entered as “Deferred Generator Installation Cost” ($/kW). This allows

the spreadsheet to calculate the “Total Generator Cost” that will be used. The Deferred Generator

Installation Cost should reflect the user’s best estimate of the “overnight construction costs” which

include all aspects from site acquisition through to commissioning and ready to operate the plant. This

number represents more than the capital cost of the turbine. It should reflect the entire costs from

inception up to the point the new capacity can deliver the targeted capacity into the utility grid. This

distinction will allow for direct comparison to the IES where the capacity can be delivered at the time of

commissioning for each site with no further investments.

The other costs that can be deferred are the Fixed and Variable Operating Costs (Opex). Fuel costs are

estimated on a $/MWh basis with the amount of energy deferred linked to the energy capabilities (found

on the “Energy Summary” worksheet of the model). Opex is estimated as a percent of total installation

costs. An inflation rate is applied to both Fixed and Variable Opex as shown on the “General Inputs”

worksheet.

Now that the installation costs and Opex have been identified, it is possible to calculate the benefit by

either deferring or eliminating the decision to invest in that peaking power generation plant. The TVM

allows selection of either “Defer” or “Eliminate” to demonstrate either scenario. It is necessary to select

a “Payment Start Year” for both “Before IES” and for “Deferred (with IES)”. This ensures that the deferral

benefit begins in the period in which the investment would have occurred, while also indicating the year

in which payments would begin after deferral. For example the user may enter a deferral of one to many

years for generation capacity which is already planned for the future.


The “net” benefit is quantified by calculating the expected cost streams for both “Before IES” and “After

Deferral”. The difference between these streams is used to estimate the “net” benefit of the deferral (or

elimination).

In addition, the environmental benefit of the deferral is also shown based on assumptions for reductions

in CO2e. See the “Environmental Benefits” section for further details.


ENERGY SALES

OverviewThe IES provides two‐way verifiable demand side management that enables energy to be sold at market

rates.

The maximum available capacity is typically available during peak times (e.g. hottest times of day) when

market prices for peak capacity are highest.

ValueComponentsGuaranteed Capacity

Market Price

Hours Available

Figure 5: An example of the IES Capacity and Available Hours for a 50MW project

ApproachUsing the Energy Summary worksheet as a basis for the expected energy available from the IES, the

value of the energy can be determined by applying both a price for the energy ($/ MWh) and a quantity

(MWh) to the “tiers” of energy shown in the IES and illustrated in Figure 5.


The “Energy Sales” worksheet allows a price assumption ($/ MWh) for each tier of capacity (to recognize

that the highest tiers of capacity are likely to occur at peak demand periods which will likely have a

different (usually higher) price. These prices are then inflated year over year consistent with the

inflation assumption on the General Inputs worksheet.

The Energy Sales can then be calculated by multiplying the inflated energy price by tier times the energy

available in that tier as shown on the Energy Sales Worksheet.

The total Energy Sales is the sum of the energy sales benefits from each tier.


RETURN ON ASSETS

OverviewThe IES is a unique solution that is classified as a plant‐in‐service asset based on the two‐way, verifiable

operation allowing it to become a reliability asset for the grid. FERC uniform code of accounts rule 371

defines the allowance for installation of instrumentation, control equipment, and switching equipment

(such as lighting contactors) on customers' premises as follows:

“This account shall include the cost installed of equipment on the customer's side of a meter when the utility incurs such cost and when the utility retains title to and assumes full responsibility for maintenance and replacement of such property. This account shall not include leased equipment, for which see account 372, Leased Property on Customers' Premises.

Items

1. Cable vaults.

2. Commercial lamp equipment.

3. Foundations and settings specially provided for equipment included herein.

4. Frequency changer sets.

5. Motor generator sets.

6. Motors.

7. Switchboard panels, high or low tension.

…switchboards with panel wiring, panels with instruments and control equipment only, panels with switching equipment mounted or mechanically connected, trunktype boards complete, cubicles, station supervisory control boards, generator and exciter signal stands, temperature‐recording devices, frequency control equipment, master clocks, watt‐hour meter, station totalizing wattmeter, storage batteries, panels and charging sets, instrument transformers for supervisory metering, conductors and conduit, special supports for conduit, switchboards, batteries, special housing for batteries, protective screens, doors, etc.”

This enables the utility to put the investment in the IES into its rate base as an asset upon which it can

earn an allowed rate of return.

ValueComponentsBeginning Asset Value

• Contract Capacity • Installation Cost ($/kW) • Total Installation Cost

Asset Life (To estimate depreciation) Asset rate of return


ApproachThe “Return on Assets” worksheet first determines the beginning basis for the asset value by calculating

the “Installation Cost” or capex needed to install the solution. This is based on the Contract Capacity

(MW) and an installation price ($/ kW). This can then be used to determine the “Total installation cost”.

As with the Generator Deferral, the Installation Cost should reflect the entire costs from inception up to

the point the new capacity can deliver the targeted capacity into the utility grid.

The total installation cost then has an assumed “Innovari Plant in Service Life (Years)” that is shown on

the “General Inputs” worksheet. This allows an annual depreciation amount to be calculated for the

plant‐in‐service asset (assumes a straight‐line depreciation method), enabling the beginning and ending

depreciated asset value to be calculated each period. This result is then used to determine an average

asset value for the period, on which the assumed “rate of return” can be applied to estimate the final

“Return on Asset Value” by year.


FEEDER DEFERRAL

OverviewInnovari works directly with utilities to identify a deployment plan that addresses the constraints within

their distribution system

Specific feeders can be targeted to relieve constraints or to provide head‐room for future growth

ValueComponentsNumber of deferred feeders

• Target feeders and MW deployed per feeder • Percentage of target feeders to relieve constraint • Total deferred feeders

Re‐conductor cost • Average feeder length • Total length of deferred conductors (e.g., single phase, three phase or 4 wire) • Total re‐conductor cost per foot


ApproachThe targeted nature of the IES enables the deferral of Feeder upgrades by enabling a reduction in peak

demand on feeders that would otherwise be constrained, requiring replacement, upgrading, or re‐

conductoring.

The approach used to determine the value of this benefit was to first estimate how many feeders would

likely be deferred for a given IES Contract Capacity level (e.g., a larger IES installation can allow the

deferral of more feeders). Based on typical re‐conductor costs, attributes, and lengths a deferred cost

can be estimated.

First the IES Contract Capacity (MW) is used from the “General Inputs” worksheet and an “Average MW

per Target Feeder” is assumed in conjunction with the number of target feeders and the percent of

feeders that are addressed. For example, a 50 MW Contract Capacity IES might be deployed across a

total of 50 feeders: 1 MW deployed for each feeder on average. Of these 50 feeders, some may be

more constrained than others. The “Percentage of Target Feeders to Relieve Constraint” reflects the

user input of feeders that are likely constrained. e.g. if 20% of the above example was used,

approximately ten feeders would be eligible for deferral (or elimination) of re‐conductoring. 20% of 50

= 10. In this manner the user can define the saturation potential of the project and specifically account

for targeted feeder deferral.

Attributes of the deferred feeder are used to estimate the expected total reconductor cost (in “year

one” terms where year one is current year and represents the known costs of such projects) since costs

will likely change with inflation. The assumptions shown are the average length of the feeder, or section

of feeder implied for re‐conductoring (in miles), enabling an estimate of how many “feet” of conductors


can be deferred (or eliminated). An assumed “re‐conductor cost per foot” is then applied to estimate

the total “year 1” Re‐Conductor cost. The reconductor cost should reflect the user’s loaded cost of such

a project as properly accounted for as an added capital asset to the utility grid including poles, wire,

cross‐arms, capitalized labor, and any other normal project loading. (later inflated by an assumed

inflation taken from the “General Inputs” worksheet.)

The total installed cost is inflated to the year that the project starts and then an estimated payment

stream is determined using the WACC assumed on the General Inputs worksheet. That payment stream

represents the “payment” for a loan that would pay for the installation that begins in the period shown

under “Payment Start Year” both before and with the IES.

Similar to the approach taken on the Generator Deferral worksheet, the payment stream can either be

deferred by selecting “Defer” or eliminated by selecting “Eliminate”. In a high‐growth area the re‐

conductor activities might get deferred for 10, 15, or 20 years as an example, whereas in stable areas

with lower growth, there may be a complete elimination of the re‐conductor needs for the foreseeable

future. It should be noted that TVM allows for forecasting as many years as the user desires. Most

distribution planning is performed on a 5 year planning horizon. This tool allows the utility to extend the

forecast of IES benefits as it may be deployed across multiple years and provide relief for tens of years in

the future.

The “payment” for the re‐conductor activity is then shown as a payment stream “Before IES” and one

“After Deferral” and the difference is then used to estimate the total deferral (or elimination) benefit.


ANCILLARY SERVICES

OverviewThe unique characteristics of the IES enable use of the solution in the Utilities Ancillary Services portfolio

Contract capacity and additional capacity products (e.g. Medium, High, and Grid Emergency) are

available as ancillary service products

ValueComponentsCapacity

• Capacity for each product at contract temperature (Low, Medium, High, Grid Emergency) • Adjustment for temperature • Adjustment for occupancy • Net Ancillary Services Capacity (kW)

Price • Ancillary Services Price ($/ kW – Year)

ApproachThe IES can be used as part of a utility ancillary services portfolio. This benefit is calculated by first

assuming the expected Price for ancillary services in that region ($/kW – Month) and then applying that

price (after inflation) to the expected capacity available (kW) for the solution.

The price is assumed on Ancillary Services worksheet as an input. The capacity of the solution is based

on the Contract Capacity plus any “additional tiers” of capacity for higher levels such as Medium, High,

and Grid Emergency capacity products. The Ancillary Services worksheet has an assumption section

which allows the ratio of available capacity in these higher tiers to be expressed as a percentage of the

“Contract Capacity”. For example, a 50 MW Contract Capacity product might have 10 MW of Additional

capacity (20% of contract level) available in the “Medium” tier. “Switches” for Include or Exclude are

provided in each tier of capacity.

Once the price and starting total capacity are available, the capacity is further adjusted downward to

account for effects on the total capacity from variations in Temperature and building Occupancy. These

total adjustments (shown as a negative percent) allow an effective Net Ancillary Services value to be

obtained.

This “Average” capacity available for Ancillary Services can then be multiplied by the inflated price each

year to determine the total ancillary services benefit for each year.


LOST REVENUE RECOVERY

OverviewThe IES enables an energy savings benefit to the end‐use customer.

Some regulatory environments allow a portion of the “lost” revenue on saved energy to be recovered

through a pre‐defined recovery structure.

ValueComponentsTotal energy available for the IES is computed

A percent of hours that is available for recovery is applied to determine the energy available for

recovery

The energy available for recovery is then multiplied by a recovery rate (with any applicable inflation) to

determine the final value of the Lost Revenue Recovery

ApproachThe energy available in the IES solution is based on the capacity in each group and the available hours.

For Lost revenue recovery, an additional assumption on the “Percent of Hours Eligible for Recovery” is

also shown. This is utility‐specific but allows a portion of the total energy to be considered eligible for

this benefit.

An assumption is also made on the recovery rate ($/ kWh) for this “lost revenue recovery”.

Using the standard assumptions on capacity and hours available by group for the IES, combined with the

assumed percent of hours eligible for recovery, then the total “energy” available for recovery by group

can be determined. This energy by group is then multiplied by the inflated pricing (again inflated by a

percent shown on the General Inputs worksheet).

Once the energy and inflated price are shown by year, the results are multiplied together by group then

totaled to calculate the Lost Revenue Recovery values on the Lost Revenue Recovery worksheet.


ENVIRONMENTAL BENEFITS

OverviewThe energy reduced by this solution provided direct environmental (e.g. CO2e) benefits proportionate to

the energy mitigated

ValueComponentsSelection and summary of energy savings that provide emissions benefits

US average or utility‐specific generation portfolio mix used to determine CO2‐equivalent emissions (lbs/

MWh), or other user defined generation mix.

CO2e Cost ($/ Ton) ‐ Year 1 Total emissions (lbs CO2e)

Conversion to Barrels of oil consumed, vehicles, etc.

ApproachThe environmental benefits of the solution can be quantified by applying the energy savings from the

solution to expected emissions for the respective energy savings sources. The final environmental

benefit value can then be determined by applying a CO2e (C02 equivalent) in $/ Ton to estimate the

actual value.

The General Assumptions worksheet of the TVM workbook enables an input for the cost of CO2e

emissions represented as $/Ton in year 1. Subsequent years have an inflation rate for Carbon Cost

(from the General Inputs worksheet) that is applied. Other basic conversions including lbs per Ton and

lbs per Metric ton are shown for reference and are used in some conversions on the worksheet.

The Generation Mix section enables inputs for the emissions (lbs/ MWh) for varying generation types

including:

Coal

Gas

Biomass

Oil

Nuclear

Other

In addition, the percent of generation for the given utility can be used to enable a portfolio‐wide

blended emissions rate (lbs/ MWh).

The default (U.S. National Averages) are shown as a baseline reference for emissions by generation type,

however a “User Selected Value” section enables a user to enter custom values. If custom values are

used, select the “User” switch next to the “Generation Assumption Source” label to use custom values


rather than the “Default” switch which will use U.S. averages as a basis for emissions by type of

generation and mix of generation types.

Because energy savings for some value drivers directly offset a particular type of generation (e.g. peak

generator deferral), the emissions rates per MWh are varied by generation type to accommodate this.

Environmental benefits are calculated for several sources with the emissions basis indicated in italics:

IES Savings (Directly offset by solution) – Blended average Emissions Rate

Generator Deferral (Energy offset by deferring a peak generator) – Emissions Rate ‐ Gas

System loss savings (Energy offset that would have been lost in transmission and distribution) – Blended average Emissions Rate

BMS Energy Savings: (Energy saved on end‐use customer sites through increases in efficiency due to improved scheduling and building management offered by the building) – Blended average Emissions Rate

The energy saved for each category above comes from their respective worksheets in the model to

ensure a link with the value driver (with the IES Savings coming from the Energy Summary worksheet).

Using the energy saved by category above, with the respective Emissions Rate listed in italics, the

emissions in lbs of CO2e is calculated. That value is then converted to tons CO2e, after which an

emissions cost in $/ ton (inflated) is applied to get the savings by category. The total for all categories

represents the total savings for emissions. Note that each source on the list above can be included or

excluded from the benefits calculations by clicking “Include” or “Exclude”.


BMS ENERGY EFFICIENCY SAVINGS

OverviewBuilding Management Systems (BMS) provide meaningful energy savings to the end‐use customers

A significant number of customers receiving the IES do not already have a BMS and can benefit from the

scheduling and monitoring capabilities built into the IES

ValueComponentsNumber of buildings

Contract Capacity

Contract Capacity (kW) per Building

% buildings that do not have a BMS by type of building

Energy savings per building that did not already have a BMS (e.g. 9%)

Incentive per kWh Energy Saved

ApproachThe installation of the Innovari IES into buildings can have a significant impact on energy savings for the

building. Specifically, buildings that do not currently benefit from a BMS.

To estimate the energy efficiency benefits, the Contract Capacity is used as a scaling factor for the size of

the project from the General Inputs worksheet. Then an assumption is made on the Contract kW per

building to estimate the approximate number of buildings that will be installed. Then assumptions are

provided for the percent of energy savings that can be obtained for buildings that did not have a prior

BMS capability.

Using the total number of buildings calculated above, the type of buildings the further split out into the

following categories:

Big Box

Small Retail

Convenience

Restaurant

Office For each building type listed above the average annual consumption is provided (and can be changed as

an assumption) and the expected percent of installations is shown as an assumption to enable changes

in the expected mix of building installations. This is used to estimate the expected mix of buildings that

will be installed to meet the total # of buildings expected. The mix is important, because assumptions

on the expected percent of buildings that already have a BMS (and subsequently would not be credited

with BMS energy savings) varies considerably by building type (e.g. an office building may be much more

likely to have a BMS than a convenience store).


Assumptions are then made by building type for the % of buildings “BY TYPE” that have a BMS installed.

This information can then be used to calculate the number of installations by building type that benefit

from energy efficiency gains from a BMS‐type system. Using the average annual energy consumption by

building type, the total energy savings by building type can be obtained.

This energy savings (MWh) can then be multiplied by the incentive offered for energy efficiency gains.

Two types of incentives shown on the worksheet including “One Time” and “Recurring” as different

utilities have varying requirements.


SYSTEM LOSS SAVINGS

OverviewAs a distributed energy product, the energy savings are at the site and are not susceptible to system

T&D losses

The energy from the IES therefore enables a savings from the losses that would have occurred if

traditional supply‐side options been used. If the energy is not required to be generated and delivered

across the entire grid to the end‐use customer, the offset by delivering the IES at the customer premises

has value.

ValueComponentsEnergy from IES

MW Hours Total

(MWh)

50 300 15,000

42 100 4,200

31 100 3,100

21 376 7,896

30,196

Expected T&D losses (e.g. 10%)

Retail energy rate (e.g. $0.15/kWh) used to value savings

ApproachThe System Loss Savings benefit can be derived from the total energy from the solution, upon which an

assumption of the Transmission and Distribution (T&D) losses that would normally have occurred to

deliver that energy to a customer. In the System Loss Savings worksheet, the total energy is calculated

on the Energy Summary worksheet, then transferred to the System Loss worksheet. The expected T&D

loss % is then applied to this amount (e.g. 10%) to calculate the expected losses that would normally

occur for T&D losses. An assumption for the Commercial on‐peak energy rate ($/ kWh), inflated by year,

is then used to convert this to annual savings


SUBSTATION DEFERRAL

OverviewThe Innovari IES provides the ability to defer capital investment in substations by relieving capacity

constraints on constrained substations

ValueComponentsDeferred Substation Size per 50 MW Deployment (MVA)

Substation Cost ($/ MVA)


ApproachThe “Substation Deferral” benefit is similar to other deferral benefits in the Total Value Model. In this

case, the installation of the Innovari IES can enable a deferral (or elimination) of a substation upgrade.

An assumption is available for the size of the deferred substation (e.g. 33.6 MVA) and an expected cost

in $/MVA is used to estimate the total year 1 cost of a substation. As with the Generator Deferral, the

Installation Cost should reflect the entire costs from inception up to the point the new capacity can

deliver the targeted capacity into the utility grid. For Substations this may include control upgrades,

additional bus work or switching, addition of capacitors and any other element of the project. The user

must also define if the breakers and get‐away’s are included here in the substation cost or in Feeder

Deferral.

Based on the “base cost” of the substation, the worksheet uses the difference between the expected

payment streams “BEFORE the IES” vs. “AFTER the IES” to estimate the deferral benefit.

The expected “Payment start year” for the substation Before the IES is used as the “baseline”, and the

substation cost calculated above is inflated to match the start year and an assumed WACC is applied to

calculate the expected payment for the substation capital over the debt repayment duration.

Similarly, the Payment Start Year for the substation WITH the IES is shown with a start year that is now

later than the original start year. The difference between the start years for BEFORE and AFTER is

effectively the years of deferral.

The two payment streams are subtracted to show the net benefit. Similar to the Generator Deferral

worksheet, an assumption is available to defer or eliminate the need for the asset entirely. If so, the

cost of the solution AFTER the IES would be eliminated (if Eliminate is selected).


OUTAGE & RESTORATION

OverviewThe IES enables “last gasp” capabilities that provide valuable information on events including outages.

The utility can receive notification of outage events, including directly to an OMS system.

ValueComponentsMitigated Customer Service Calls

• Total annual calls • % call from customer group (e.g. non‐residential) • Percent from target population that would be mitigated by solution • Cost/ Call

Reduced Truck Rolls • Annual truck rolls • % feeders w/ IES • Rolls on feeders w/ IES • % truck rolls for nested outages • Cost/ Truck roll

ApproachThe “last gasp” capabilities of the system enable improved situational awareness of outages. The Energy

Agent™ includes enough non‐volatile energy storage to power the equipment and communications

following an electrical outage. The ability to gather, store and report the events relating to an outage

can be incorporated into the existing utility systems or procedures.

This information can be used to both lower call volumes (due to earlier awareness and resolution of

outages) and to reduce unnecessary services calls or “truck rolls”.

The total mitigated call volume is estimated by taking the total number of annual outage calls times an

assumption for the percent of those calls that comes from the target customer group. This yields the

number of outage calls from the target population. Using this number, an assumption on the percent

outage calls from that population that can be mitigated is then used to estimate the reduced calls per

year. The call volume reduction is then multiplied by an assumed cost per call (inflated annually) to

develop the “Reduced Call Volume Benefit”.

In a similar manner, the number of truck rolls that can be mitigated is also calculated by starting with

the total number of outage Truck Rolls, followed by a reduction based on the % of feeders with the IES

to get outage truck rolls on installed feeders. Then, an assumption on the % of truck rolls on those

feeders attributable to “nested outages’ is used to calculate the reduced “nested outage” truck rolls.

This volume is then multiplied by a typical cost per truck roll (inflated annually) to arrive at the total

truck roll cost mitigated.

The sum of both Reduced Call Volume and Reduced Truck Roll Costs represents the total Outage and

Restoration benefit.


GLOSSARY

Ancillary Services: The value from using the project as part of the utility’s ancillary services portfolio

Building Management System (BMS): A system comprised of hardware and control devices that are

commonly found in commercial buildings to control electrical loads such as lighting, heating, and air

conditioning

BMS: See Building Management System

BMS Energy Efficiency Savings: The value of the energy savings realized in buildings that do not have a

building management system (BMS) in utility territories with energy efficiency incentives in place

Carbon Dioxide Equivalent (CO2e): A measure that describes the global warming potential of different

greenhouse gasses. This enables different greenhouse gas emissions to be described using a consistent

metric. Example greenhouse gasses include methane, perfluorocarbons, nitrous oxide, and others.

Energy Sales: The value of energy sales of the guaranteed energy reduction that is available with the IES

Environmental CO2e Reduction: The value of environmental benefits such as CO2e reductions that

result from the reduction in energy generation

Feeder Deferral: The value from deferring capital investment in feeder upgrades

Generator Deferral: The value from deferring capital investments in peaking power generation plant

capacity

IES: See Interactive Energy Solution™

Interactive Energy Solution™ (IES): Innovari’s solution that enables advanced grid optimization using

sophisticated hardware, algorithms, and network operations components to manage and dispatch

resources on behalf of the utility.

Lost Revenue Recovery: The recovery of “lost” revenue allowed in some jurisdictions to compensate for

the energy savings realized by the end‐use customer

Net Present Value (NPV): A method of “discounting” future cash flows using a “discount rate” to reflect

the fact that cash flows in earlier periods have a higher value than those in the future (e.g. due to the

opportunity to invest that capital elsewhere). This is a common method of assessing the current value

of a stream of multiple cash flows over many periods of time.

NPV: See Net Present Value

Outage & Restoration: The value from last‐gasp capabilities to identify outages, increasing restoration

efficiency and mitigating unnecessary crew site visits


Return on Assets: The value of the return on the asset at the allowed rate of return that the utility can

earn on the project as a plant‐in‐service asset

Substation Deferral: The value from targeted deployment and resulting deferral of substation upgrades

by reducing peak load on those substations

System Loss Savings: The value of the energy savings as a result of decreased system losses on the grid

for demand side management projects

Total Value Model (TVM): The Total Value Model is an MS Excel Workbook developed to enable a utility

to customize their evaluation of deployment of the IES and quantify the associated value drivers.

TVM: See Total Value Model

Operating Expense (Opex): Expenses typically that include the operations of a company, project, or

generation resource. This may include labor, fuel, or other components but will typically exclude costs

for physical assets that have a longer life such as buildings, large equipment, or the generators

themselves.

Opex: See Operating Expense

Date post:	29-Aug-2018
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