CAPACITY FOR CHANGE of the...HEADQUARTERS NOC & TECHNOLOGY CENTER 2900 N. Quinlan Park Road Suite B240, #215 Austin, TX 78732 512 318 2154 19720 NW Tanasbourne Drive Suite 320 Hillsboro,

HEADQUARTERS NOC & TECHNOLOGY CENTER

2900 N. Qu i n lan Park

R oad

Su i te B240 , #215

Aus t i n , TX 78732

512 318 2154

www. i nnovar i .c om

19720 NW Tanasbou rne

D r i ve

Su i te 320

H i l l sboro , OR 97124

BACKUP DATA CENTER

Santa C la ra , CA

INNOVARI INDIA

Gurgaon (De lh i )

Mumbai

Open i ng Soon :

Banga lo re

INNOVARI LAT IN AMERICA

Buenos Ai re s , Argent i na

Em Cal i , Co lombi a

Open i ng Soon - Panama

INNOVARI MIDDLE EAST

Amman , Jo rdan

Open i ng Soon – UAE & Bahra i n

CAPACITY FOR CHANGE

History of the Demand Side

Ceylon Electricity Board - August 2015

Industry Veterans with a global

viewpoint as your partner

Confidential @ 2014 Innovari, Inc. 2

Executive Team ExperienceInnovari Activity around the world

Electricity is the ONE thing

that drives a country’s GDP

Access to reliable, secure and affordable

electricity defines a nations health, welfare,

quality of life and overall success!


Demand Side

What’s all the fuss about?

Why care about the demand side?

What benefits should we expect?

How should we measure and/or track?

What have others done?

Program Activity versus Metric Driven

Success on the Demand Side

How can we use the demand side to

achieve our goals?


•Modest improvements in load management result in large improvements in the system utilization of all

existing assets (generation, transmission, and distribution)•Defers or eliminates

costly T&D upgrades•Balance Intermittent Renewable Sources•Helps improve total system reliability

• Inclusion of load management is in line with regulatory requirements of DER in the IRP

875MW

4,000 MW

Peak**

3,125 MW at

5% of Hours

(438)

Load Duration Curve Example

The Mission:

Improving Overall System Utilization

System Utilization Improvement

Increase of 19% in

system utilization from 43% to 62%

for 5% of hours; (438 hours)

Increase of 15% in

system utilization from 43% to 58%

for 2.5% of hours (219 hours)

Traditional DR (40-60 hours)

5CONFIDENTIAL © 2015 INNOVARI, INC.

Evolution of

Load Management

Most Existing

“dispatchable load”

driven by manual

measures via call,

page or text

~90% of Worldwide

LM is here

Two-way,

verifiable load

management

with dynamic

attributes that

allow the grid to

be served

<1% of Worldwide

LM is here

Previously known

as curtailment and

resurfaced in

residential as one

way Tstats

<10% of Worldwide

LM is here

Utility Equivalent & Trusted Resource/Product

Va

lue

Looks, acts and

is trusted as a

utility resource if

owned by utilityFully automated

response

intelligently taps

embedded

responsive load

in most buildings

Any initiative that creates dynamic communication

and control across this boundary must be secured

at the highest level to protect the power grid and

the control room that is responsible to maintain the

reliability of the power grid.


Evolution of

Measurement & Verification

Eliminates all

concepts of

‘gaming’ and

difficult post

processed

settlements.

Enables LM to

be a reliability

product


Choosing a Sustainable, Lower

Cost Asset to Optimize Your GridIncreases Customer Relationship and Loyalty

Asset: Central Station

Generator

Asset: Virtual Power Plant

(Approx 50% less cost)

• Single, rate based Asset• Ongoing O&M costs

• Fuel = Fossil fuels• Ongoing, highly variable• Increases grid losses• Negative environmental

effects• No End-Use Customer

interaction

• Many distributed sites as one rate based Asset

• Ongoing O&M costs• “Fuel” = Site Incentives

• No fossil fuel or variable cost • Reduces grid losses• Positive environmental effects

• End-Use Customer incentives increase customer loyalty


Start at the lowest system level –

A single feeder

• SCADA shows ~70 hours over 500 Amps. Maximum peak ~574

Amps

• To manage 50 to 75 Amps on this feeder, 620 to 930kW of load

management would be required to keep the feeder at or below

500 AmpsConfidential @ 2014 Innovari, Inc. 9

Optimize Operational Goals

This utility was seeking to optimize feeder usage to meet

equipment operating limits and defer or eliminate the need for

feeder and substation upgrades as previously planned

Confidential @ 2014 Innovari, Inc.

Capacity threshold

Also seeking to ‘bury’ load when wind

generation peaked during off hours

Real Time Monitoring and

Two-way Closed Loop Control

A combination of operating objectives can be achieved including peak

load management to mitigate system constraints, load bury to optimize

renewable energy resource production (in this example wind at night),

and individual building management such as pre-cooling to shift load

profiles, even a few hours a day. (EX: to balance the post solar peak)

* Example illustrates 362 hours of dispatch on one feeder from a peak load reduction of 1MW to a peak load bury of 275kW

Move up a level to Substation

Pursue the entire area with emphasis on feeder 291-23 291-21

291-23

291-12

290-22

290-21

253-21

70-51

Legend:Candidate > 10 kW30 – 50 kW50 – 100 kW> 100 kW

SurveyedApprovedInstalled

Delivered Site kW

Feeder 10-30 30-50 50-100 100+ Total kW

290-21 2 1 0 0 100

290-22 2 3 3 1 700

291-12 2 2 0 1 300

291-23 4 3 6 2 900

Total (all Feeders) ~2.0MW

$4.8 million feeder reconductor

deferral on feeder 291-23

$8.7 million substation upgrade

deferral on substation 291

$1.4 million dollar ADSM project


Move to a System Level View

50 MW Project Benefits:

6 deferred substation upgrades $43M

14 deferred feeder upgrades $35M

50 MW peaker eliminated $92M

Significant Loss improvement,

reduced emissions, improved customer

satisfaction and regulatory relationship

Benefits > $ 170 M

Project cost: $35M


Program based Demand Side:

Results are not what you want

In the U.S., great things have been accomplishedEE

Emission Reductions

Deferral or Elimination of Peak Power Plants

HVDC/FACTS and Power Electronics proof of concept and deployment

Full deployment of SCADA

AMI/AMR

However, In the U.S., DR is still utilized almost exclusively for “Emergency” reasons, lawsuits are rampant for gaming and the administrative burden for base lining and settlement is still largely unknown as it is buried into other overhead costs.

The net result related to the Root Cause Problem of our Industry?

The Root Cause Problem (LDC) is WORSE!

The grid has become more ‘peaky’ driving even greater economic issues and price/cost separation from peak to baseload.


PJM (ISO) Example

PJM (Pennsylvania-New Jersey-Maryland Interconnection) operates

a competitive wholesale electricity market which serves 20 distinct

regions (T&D Utilities)

63,000 miles of Transmission Lines

61 million people

Peak Demand of 165,000 MW

Generation Capacity of 184,000 MW

DR Capacity of ~11,000 MW

DR Program Costs:

2009 $410 M and not used

2010 $584 M for 5 days of use $ 25,000 /MWh

2011 $420 M for 1 day of use $ 35,000 /MWh



Total: $2.2 BillionConfidential @ 2014 Innovari, Inc. 15

PJM: Over Two Billion Dollars

for less than 100 hrs over 15 yrs2000 No Events

2001 Events on 4 days for a total of 11 hours


2003 No Events

2004 No Events



2007 Event on 1 day for a total of 3 hours

2008 No Events

2009 No Events

2010 Events on 5 days for a total of 25 hours Dispatched 2,700 MW

2011 Event on 1 day for a total of 5 hours Dispatched 2,100 MW



Never Dispatched more than 50% of Available Capacity

Largest Event was 3.5% of Peak Demand

Equivalent Capacity Factor: 0.09% Confidential @ 2014 Innovari, Inc. 16

California Example

CAISO (California Independent System Operator) operates a

wholesale electricity market which serves three Independently Owned Utilities (IOUs) and over 25 municipal organizations

27,000 miles of Transmission Lines

30 million people


Generation Capacity of 56,000 MW

DR Capacity is estimated at ~3,000 MW

All “DR” programs are managed by the individual utilities

and are not provided as part of the daily operating forecasts.

An “event” for the CAISO is a mass media notification that the

state-wide generation capacity may not meet requirements.

Utilities may then trigger any combination of response including Interruptible

Tariff agreements, Capacity Bidding Programs and Aggregator Managed DR

programs. However, when reporting results, utilities include all other estimates

of demand reduction associated with Peak Pricing and Summer Discount

program agreements already operating prior to any “event”.


SCE Example

SCE represents approximately one half of the CAISO territory

14 million people


2013 Reduction Hours

Interruptible Tariffs $ 81.4 M 23 MW 1 hr

Price Responsive Programs $ 8.1 M 2 to 221 MW 24 hrs

Aggregator DR Programs $ 13.0 M 2 to 140 MW 50 hrs

Auto-DR $ 12.2 M Not called

Summer Discount Programs $ 92.0 M 100 to 361 MW 24 hrs

Outreach Programs $ 10.6 M 8 hrs

Program Administration $ 4.4 M

Total: $ 220 M for 12,400 MWh $18,000 /MWh

Largest Single Day Event was 2.0% of Peak Demand

Equivalent Capacity Factor: 0.6%


ADSM is a game changer

Improve System Load Factor (System Utilization) by 20% (Dramatically

improve the utilization of existing and future assets)

Defer or eliminate “Inefficient Regulatory Assets” (Feeder

reconductor, substation upgrade, etc)

Defer or eliminate a portion of the required peaking power plants

Eliminate the need to burn fossil fuels for Ancillary services such as

spinning reserves

Real time phase balancing

Real time aggregation of DER (Solar, Battery, Generation, etc.)

Real time balancing of central station or distributed intermittent

resources

Put the control in the hands of the utility/grid operator and improve

both the regulatory and consumer relationship

Dramatically improve Grid Situational Awareness to the lowest level

of the network – to the “edge of grid”


But is it economic?


Any effort undertaken

should strive to connect

utilities, their customers,

and their communities to

improve how the world

uses energy.

Crucial for an island economy to utilize and optimize

every resource available to the gridConfidential @ 2014 Innovari, Inc. 21

A Platform that delivers now

and enables the future

HVAC Other

Load

Lighting

Building Load

Phase Independent

Battery Storage

Generator

Solar Panel

Energy AgentTM

Balances

Distributed

Energy

Resources

Now: Two-way, verifiable,

closed loop control. ADSM

dispatched by the utility.

The possibilities go far

beyond load management.

Ancillary services (Spin and

Non-Spin reserves), feeder

management, substation

management, congestion

management, peaking

generator deferral or

elimination, positive

environmental benefits, etc.

Now and in the future: Utility enables edge-grid

technology and DER, even microgrids. Incorporate

customer-owned, or in the future, utility-owned

distributed generation. Manage distributed solar

with building loads where it is deployed or with

additional load on the feeder so the whole system

is not affected by this resource. Balance

intermittent renewables and utilize battery storage.

Balance central station renewables. Incorporate

distributed storage and use it to optimize phase

balance and feeder efficiency as well as protect

customers from outages.Grid Anaytics

Now and in the future:

Utility has greater visibility

deep into the grid, with

advanced monitoring and

analytics:

• Volt / VAR,

• Power Quality,

• DG & PV

integration/monitoring

• Harmonics

• Digital Fault Recording

• Distribution level PMU

Energy

Agent™(at customer site)

Grid

Agent™(at site or

on feeder)

DER

Agent™and “edge grid”

technology

enablement

Interactive

Energy

Platform™

Continue on this path?


875MW

4,000 MW

Peak

3,125 MW at

5% of Hours (438)

Load Duration Curve Example

250MW

~$2B of

Generation

Investment

~$500M in T&D

“Industry Average Utilization of 43%”

U.S. Energy Information Administration (EIA)

Billions spent on

underutilized

infrastructure

Fuel costs and emissions

increased through use

of inefficient peaking

power or hot stand-by

Peaking units use

increased and life

decreased to attempt

to balance renewables

on the grid

Customers resources

stranded and not

dramatically under

utilized

System technical losses

and imbalance

increasing over time

Or create a new one!


Increase Average Utilization to 60%!

HEADQUARTERS NOC & TECHNOLOGY CENTER

2900 N. Qu i n lan Park

R oad

Su i te B240 , #215

Aus t i n , TX 78732

512 318 2154

www. i nnovar i .c om

19720 NW Tanasbou rne

D r i ve

Su i te 320

H i l l sboro , OR 97124

BACKUP DATA CENTER

Santa C la ra , CA

INNOVARI INDIA

Gurgaon (De lh i )

Mumbai

Open i ng Soon :

Banga lo re

INNOVARI LAT IN AMERICA

Buenos Ai re s , Argent i na

Em Cal i , Co lombi a

Open i ng Soon - Panama

INNOVARI MIDDLE EAST

Amman , Jo rdan

Open i ng Soon – UAE & Bahra i n

THANK YOU!

Questions?

Traditional Peaker (2-6 or ??? Years) Innovari IES (6-24 months)

Purchase Land

Siting Process

EA/EIS - Environmental Permits

Interconnection Study

Gas Line Extension

Construction Costs/Delays

Interconnection Facility

Total delivered at end of project

Losses on Grid (10% = Lose 5 MW!!)

Increases Spinning Reserve Requirement(12% = Build another 6 MW!!!)

50MW – 5MW – 6MW = 39MW IRP EFFECT

Delivered for $1,500 to $2,500 per kW

O&M and Fuel Variable each year

New Emissions and increased fuel requirement

$75-$125M capx - $4-$8M opex

variable

No Land

No Siting Process

No EA/EIS or Permits (RECs!!!)

No Interconnection Study

No Gas Line Extension (No fuel cost)

No Construction Costs/Delays

No Interconnection Facilities

Delivered as acquired – even day one!

REDUCES losses (Gain 5 MW)

REDUCES Spinning Reserve Requirement (Gain 6 MW)

50MW + 5MW + 6MW = 61MW IRP EFFECT

Delivered for $695 per kW*

Annual Programmatic fixed $43 per kW-yr*

Reduce current and future emissions and fuel use

$34.75M capx - $2.15M opex

fixed

The Choice for a Utility – 50MW of What?

*plus applicable shipping/tax/customer incentive/etcConfidential @ 2014 Innovari, Inc. 26

Documents

CAPACITY FOR CHANGE of the...HEADQUARTERS NOC & TECHNOLOGY CENTER 2900 N. Quinlan Park Road Suite B240, #215 Austin, TX 78732 512 318 2154 19720 NW Tanasbourne Drive Suite 320 Hillsboro,