Leadership – Consulting vs. Utility Discussion€¦ · 2? 3? 5? 7? ROI Fundamentals Who chose the...

Leadership – Consulting vs. Utility Discussion

Joel Bladow Sr. VP, Transmission

Tri-State Generation & Transmission Association

Jim Hogan Sr. VP, Transmission & Distribution Services

Burns & McDonnell

Financial Justification Fundamentals

Richard Peña Principal Consultant

C M Lantana Consulting

ROI FundamentalsRMEL DISTRIBUTION SUBCOMMITTEEOCTOBER 10 , 2019RICHARD PEÑA

ROI FundamentalsThe justification for a new project is based on:

Financial Analysis + Intangibles

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ROI Fundamentals

We Will Concentrate about 90% of our time today on Financial Analysis

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ROI FundamentalsMost Common Financial justification is Payback.But what does Payback mean, and how is it calculated?

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ROI FundamentalsPayback is usually categorized as the Maximum Time required in Years for an initial investment to be recouped by savings OR revenue. Payback Time is called Hurdle Rate.

But how many years, and why? 1? 2? 3? 5? 7?

ROI Fundamentals

Who chose the Hurdle Rate?

ROI FundamentalsArrow out = Cash Flow out of the companyArrow in = Cash Flows into the company

ROI Fundamentals

ROI FundamentalsAlternative A: $5,000. in annual maintenance (-)Base Alternative : $15,000. in annual maintenance (-)

Alternative A – Base Alternative = Savings-$5,000 – (-$15,000) = Savings-$5,000 + $15,000 = $10,000

ROI FundamentalsDraw pictures of the following investments :

– A SCADA replacement will cost $5,500,000 and save $1,500,000 per year in maintenance costs

– A PT/AT relay upgrade program will cost $200,000 and save $50,000 per year in downtime and maintenance costs.

ROI FundamentalsSCADA Replacement

At the end of:

Time 0 Year 1 Year 2 Year 3 Year 4 Year 5

Cash Flows (5,500,000) 1,500,000 1,500,000 1,500.000 1,500,000 1,500,000

Cumulative Cash Flows

(5,500,000) (4,000,000) (2,500,000) (1,000,000) 500,000 2,000,000

ROI FundamentalsPT/AT Relay Replacement

At the end of:

Cash Flows 50,000 50,000 50,000 50,000 50,000

CumulativeCash Flows

(200,000) (150,000) (100,000) (50,000) 0 50,000

ROI FundamentalsProblem 1

• Upgrade switching station• Engineering: $450,000• Materials: $250,000• Construction: $550,000• Annual Savings: $400,000/year

• With payback hurdle of three years, is this project financially justified?

At the end of:

Cash Flows (1,250,000) 400,000 400,000 400,000 400,000Cumulative Cash Flows

(1,250,000) (850,000) (450,000) (50,000) 350,000

• On Problem 1, Savings are now recalculated to $450,000 /year.• With payback hurdle of 3 years, is the project now justified?

At the end of:

Cash Flows (1,250,000) 450,000 450,000 450,000 450,000

CumulativeCash Flows

(1,250,000) (800,000) (350,000) 100,000 550,000

ROI Fundamentals Problem 3

• In order to meet quarterly dividend, Management has stopped all capital projects. Every project is now required to have a two year payback.

• On Problem 2, Engineering is complete and materials are on order. There is still time to cancel materials with no penalty.

• Engineering savings have been reviewed and revised to $400,000 per year.

• Is the project able to meet the two year payback and be financially justified?

At the end of: Time 0 Year 1 Year 2 Year 3Cash Flows: (800,000) 400,000 400,000Cumulative Cash Flows

(800,000) (400,000) 0.

ROI Fundamentals• Key Point:• IGNORE SUNK COSTS WHEN

REEVALUATING FINANCIAL JUSTIFICATION!!

ROI Fundamentals Primary Flaw of Payback:

No time value of money!

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ROI FundamentalsSecondary Flaws:

–Hurdle Rate Time Frame is arbitrary.

–Cash Flows after the Hurdle Rate are ignored.

ROI Fundamentals

ROI FundamentalsNet Present Value (NPV)Formula:

NPV= Present Value of Future Cash Flows (PVFCF) – Investment (I)

If NPV is positive, accept the project.

ROI Fundamentals• Using an Interest Rate:

• Compounding: Moving money forward in time.

• Discounting: Moving money back to in time.

ROI FundamentalsExample 1

ROI Fundamentals Example 1

Use 8% interest

Solve for $12,000 at year 0Year 3: $12,000/1.08 = $11,111Year 2: $11,111/1.08= $10,288Year 1: $10,288/1.08 = $ 9,525Year 0: $ 9,525/1.08 = $8,820

NPV = $8,820 - $10,000 = -$1,180

ROI FundamentalsPresent Value Table

ROI Fundamentals

$12,000 X .735 (4 years @ 8%) = $8820Present Value – Investment = + / -

$8820 - $10,000 = - $1,180

Reject this investment.

ROI FundamentalsOR: Use a website (i.e.,www.calculatestuff.com)

ROI FundamentalsExample 2

• Interest Rate 8%• Solve for each Annuity NPV at Year 0, then add for

Total Value• Year 4 NPV: 4 X .735 = 2.94• Year 3 NPV: 4 X .794 =3.18• Year 2 NPV: 4 X .857 = 3.43• Year 1 NPV: 4 X .926 = 3.7• Total NPV: 2.94 +3.18 + 3.43 + 3.7 = 13.25

• NPV = 13.25 – 14.00 = - $ 750

ROI Fundamentals Annuity Table

NPV = Present Value of Future Cash Flows –Investment

NPV = ( 4,000 X 3.312) – 14,000 = -$ 750

OR: Use a Website(i.e.,www.Moneychimp.com)Find Calculator, then Present Value of Annuity

ROI Fundamentals Problem 1 (Revisited)

Engineering - $450,000Material - $250,000Construction - $550,000Interest – 8%

Annual saving - $400,000Assume 5 year lifeUse NPV Calculation

At the end of Time 0 Year 1 Year 2 Year 3 Year 4 Year 5

Cash Flows (1,250,000) 400,000 400,000 400,000 400,000 400,000

(1,250,000)

NPV= ( 400,000 X 3.993 ) = $1,597,000 - $1,250,000 = $347,200

Underground Vault UpgradeEngineering - $300,000Materials - $400,000Construction - $300,000Reduced Maintenance : Years 1-5 Annual savings- $70,000Reduced Maintenance : Years 6-10 Annual Savings- $140,000Improved SAIDI: $50000/AnnuallyAssume 8% Interest AND 10 year life

Use NPV to calculate benefit.

At the end of

Time 0 Year 1

Year 2 Year 3 Year 4 Year 5 Year 6 ------ Year 10

Cash Flows (1,000,000) 50000 50000 50000 50000 50000 50000 50000 50000

Cash Flows (1,000,000) 70000 70000 70000 70000 70000 120000 120000 120000

(1,000,000)

SAIDI Benefit: $50,000 X 6.71 = $347,200.Reduced Maintenance Years 1-5:$70,000 X 3.99 = $279,300.Reduced Maintenance Years 6 – 10:$140,000 X 3.99 = $558,600;Present Value of $558,600 $558,000 X (.735) = $410,571

Total Benefit = $347,200 + $279,300 + $410,571 = $1,037,071

NPV Fundamentals Problem 4

NPV = $1,037,071 - $1,000,000 = $37,071

ROI Fundamentals

NPV Considerations:Interest RateEvaluation PeriodsDepreciationTaxes Salvage & Working Capital

ROI Fundamentals

The Strategic Intangible Factors

ROI Fundamentals• Customer Satisfaction (internal and external)• Employee Satisfaction and Development• Brand Equity • Infrastructure• Environmental (Non Regulatory)• Safety• Community

ROI FundamentalsSavings or Intangibles?• Upgrade of Work Order Management System with new

functionality and process redesign• SCADA upgrade• Downtown network equipment upgrade• Vault Flash Protection • SAIDI • SAIFI

ROI Fundamentals

Financial Analysis + Intangibles

Good Luck and Remember When Planning for the

Future, and the Payback looks too easy:

This Photo by Unknown Author is licensed under CC BY-NC

Don’t Forget to NPV!

Thank You

Go Broncos

Utility Emergency Reaction Panel

Patrick Hanrahan Assistant General Manager – Retail

Nebraska Public Power District

Travis Johnson Manager, Electric Distribution Standards

Xcel Energy

Frank Sanderson Manager, Metro Distribution Maintenance

Arizona Public Service

Patrick Hanrahan Assistant General Manager – Retail

Nebraska Public Power District

RMEL Distribution Engineering ConferenceUtility Emergency Reaction ResponseOctober 2019Pat HanrahanAssistant General Manager - Retail

NPPD 2019 Emergency ResponseLessons Learned

NWS Forecast March 13• Heavy Snow in February• Extremely Cold Temperatures in

February – Early March• Ground Frozen – 25” Deep• Ice in Rivers• Warmer Temps in mid-March

• Snow Melt• Swollen Waterways• Saturated Ground

System Impacts

North ForkElkhorn River

Norfolk, NE• March 2019• Building Evacuation

– Operations– Call Center

• Alternate Call Center Site Impacted– Limited Travel– Alternate Site

Limitations

SubstationsNorfolk, NE

• Substation Flooded• Communications

Impact• Water Level in Control

Building and Impacted Equipment

Columbus, NE• March 2019• Town Isolated• Alternate Call Center

– New Phone System– Call Coverage

Columbus, NE

March 2019 Road Closures

• July 2019 Flash Flood• Building Evacuation

– Operations– Control Center

• Alternate Site Impacted• New AMI System

Kearney, NE

• Alternate Site Readiness– Site Accessibility

• Testing Technology Upgrades– Phone System– AMI System

• Identify / Monitoring Critical Infrastructure– Buildings – IT/Telecom Equipment– Lines / Substations– Customer Facilities

• Employee / Workforce Impacts• Flooding Creates Long Term / Ongoing Challenges

Lessons Learned

Questions?

Stay connected with us.

Travis Johnson Manager, Electric Distribution Standards

Xcel Energy

Presented byTravis Johnson

Manager, Electric Distribution Standards

2019 FALL RMELSTORM DAMAGELESSONS LEARNED

LESSONS LEARNED FROM STORM

• Structure design has improved storm performance and restoration time– Grade B construction– Fiberglass arms– Larger washers for pins– Prevent hardware from loosening (e.g., MF locknuts, torque requirements)– Engineer your structure to perform for a storm

• Pole should fail last (longest repair)• Insulator pin should fail first (quickest repair)• Larger washers help arm performance• Fiberglass arm hardware can loosen in Galloping situations – Engineer

out the risk• Taller post insulators have greater risk for arm damage• The following presentation will show the storm damage and share some

of our solutions that we are implementing

2017 - JUPITER STORM

• Over 58,000 Xcel Energy Customers Impacted• The storm severely damaged trees and power lines in Panhandle, Borger,

Pampa, Dumas, Stinnett, Spearman and Perryton• Damage To Over 7,500 Structures

– 1,350 power poles

– 2,300 cross-arms

– 6,000 insulators

– Over 9 miles of conductor• A 73 mile portion of a 34.5kV line serving the communities of Higgins,

Follett, Lipscomb, and Darrouzett was ravaged

2017 – STORM JUPITERSTRUCTURE DAMAGE

• Infrastructure Age –– Some assets new as two months old – Some are over 50 years old – Asset renewal can reduce but not eliminate failures from icing events

• Damage on both Grade C and Grade B construction – Cross arm Failure Ice loading in some areas added 500+ pounds per phase

based off icing profiles – Arm pin failure on fiberglass arms

2017 – STORM JUPITERFIBERGLASS CROSSARM DAMAGE

• Failures– Conductor 4/0 ACSR Ultimate Tensile Strength – 8,300 lbs. force

2017 – STORM JUPITERFIBERGLASS CROSSARM DAMAGE

2016 STORM DAMAGE - CO

UPLIFT ON POLES

TRACKING ON FIBERGLASS ARM

Frank Sanderson Manager, Metro Distribution Maintenance

Arizona Public Service

Emergency Response

Frank Sanderson

Emergency ResponseBattling the Unknown

Incident Command

• Storm Related Emergency• Winter Conditions (Ice and Snow)• Floods• Mutual Assistance• Human or Foreign Interference

Emergency Response….

Plus…A Fatality or Serious Injury

• Large Number of Customers Out• Key Network Customers Out• Network Equipment/UG Cable Project Between Phases

Incident Command

Resources

Outages

Local Gov.

Traffic and Rail

Regulatory

Company Legal and Investigation

Current Condition

Grieving Family and Co-WorkersRestoration

Initial Cause and Safety PrecautionsOSHA

Recovery of Victim

Switching and Clearance

Special Skills

Road Closures

Police/Fire

Current Loading

Scope and Replacement

Curious Citizens

Compromised Workforce

Initial Lessons Learned

• Emergency Restoration has to be handled differently from an IC perspective when serious injury or death is involved.

• Need more depth in specific maintenance skills.• Better Depth in Municipal Relations• Site Control Needs Improvement• Less is More

Arc Flash Considerations with Distribution Overcurrent Protection

Timothy Day Sr. Application Engineer

EATON Corp.

Arc Flash Considerations with Distribution Overcurrent ProtectionTimothy Day, Sr. Applications Engineer OCT 2019

Arc Flash History

• June 1982 paper by Lee, “The Other Electrical Hazard: Electrical Arc Blast Burns.”• Burns from Arc Flash cause most injuries in electrical-related

accidents.

• Shifted understanding away from earlier assumptions of Electrocution as the major electrical hazard

• Formed working relationship between exposure time and human skin temperature

• Onset of curable skin burn

• Onset of tissue death

Arc Flash History

• Feb 2000 paper by Doughty, Neal, and Floyd, “Predicting Incident Energy to Better Manage the Electric Arc Hazard on 600V Power Distribution Systems”• 3- tests up to 50 kA short-circuit fault current.

• Many structured faults with arcs in open air and in a cubic box

• Established the contribution of intensified reflected heat from enclosure surfaces directed toward the opening

Standards Addressing Arc Flash Hazards

• NFPA 70E; Electrical Safety in the Workplace

• Quantifies energy from arc flash in

• Recommends arc flash rated Personal Protective Equipment PPE

• IEEE 1584; Guide for Arc Flash Calculations

• Formulae for calculations

• Excel Spreadsheet

Arc Flash Calculations; IEEE 1584

• 2002 Edition• Incorporated some work by Lee and Doughty • 300 Arc-Flash tests to develop empirically

derived equations• Up to 15kV; up to 106kA

• 2018 Edition• 2000 additional tests over range of voltage

and parameters• Variations in Electrode Configurations

Arc Flash Calculations; IEEE 1584

• Variations in Electrode Configurations2002 only 2002 only

VCB:Vertical

Electrodes in a Metal Box

VCCB:Vertical

Electrodes in an Insulating Barrier in a Metal Box

HCB:Horizontal

Electrodes in a Metal Box

VOA:Vertical

Electrodes in Open Air

HOA:Horizontal

Electrodes in Open Air

Arc Flash Events• Causes

• Contact with Energized Conductors• Dropped Tools• Mis-aligned Parts or Material During Equipment Movement

• Insulation Failure• Over-voltage• Contaminants

• Dust• Corrosion• Condensation

Arc Flash Personal Protective Equipment PPE

• NFPA 70E (2018) defines four categories of PPE

• Each category prescribes a minimum Arc Rating value for a calculated incident energy exposure.

• Represents amount of on a (multilayered system of) material resulting in 50% probability of onset of second degree burn injury.

• Arc Flash Risk Assessment . . . Shall determine if an arc flash hazard exists . . . Shall determine• Appropriate Safety-Related Work Practices• The Arc Flash Boundary

• The Personal Protective Equipment PPE to be used within the Arc Flash Boundary

• Shall be reviewed periodically, not exceeding 5 years.

NFPA 70E

Enforced By OSHA

Calibrating the term “Incident Energy”

• One second flame duration at 1 cm distance exposes 1 square centimeter of skin to 1 calorie of energy 1 cm

• I.e., Incident Energy =

• The incident energy resulting in the onset of a second degree burn =

NFPA Categories of PPEPPE Category Arc Rating Equipment

1 1.2 – 4

2 4 – 8

3 8 – 25

4 25 – 40

NFPA Categories of PPE

Above 40 Cal/cm2

Level DANGEROUS

• If energy above 40 , LV and HV compartments areinaccessible until all upstream devices are opened

Study Activity• Traditional Fault Studies

• Calculate Maximum Available Short Circuit Current• Select Equipment to Withstand and Interrupt the Current• Determine Protective Parameters for Device/Device

Time-Overcurrent Coordination

• Arc Flash Studies• Estimate Reduction of Current due to plasma vapor• Determine Fault Clear Times based on Protective Settings• Use Empirical Formulae, based on arc model, to calculate

Incident Energy at various Working Distances

Study Activity; Empirical Formulae, an intro.

Arc Flash Study• The Arc Flash study estimates incident energy and PPE

requirements at typical working distances, using:• Short Circuit Calculations; Empirical Equations; Device Operating Times

Incident Energy Sensitivity: Arcing Time

I.E. (

Arcing Time (sec)

• Calculated Incident Energy is directly related to fault duration time

Incident Energy Sensitivity: Distance

I.E. (

Distance (mm)

• Calculated Incident Energy is inversely related to the distance from the arc point to the person

Incident Energy Sensitivity: Distance

I.E. (

Bolted Fault Current (kA)

• Calculated Incident Energy is logarithmically related to fault current magnitude

• Note: Higher fault currents may actually yield lower IE due to faster protection speeds

Reducing Incident Energy• Clear the Arcing Fault Faster

• Reduce Pickup and Delay Settings

• Enable Instantaneous Elements; Maintenance Mode

• Differential Protection

• Smaller Fuses

• Optical Sensors

• Reduce Fault Levels (assuming no increase in trip times)

• Current Limiting Fuses

• Block Paralleling Capabilities

Reducing Incident Energy• Assuming the same arcing fault current

• Faster Clear Time = Lower Incident Energy

• Small changes in protective device settings = significant impact on Incident Energy values.

Current240 A 600 A 1200 A

CurrentPick Up

Reducing Incident Energy• Faster Clear Time = Lower Incident Energy

• Changes in Overcurrent Protection can reduce Clear Time.

Reducing Trip Threshold

Reducing Time Delay

Reducing Incident Energy

• Normal Settings• 10.7 ; PPE Category 3

• Activation of ARMS (Arcflash Reduction Maintenance System)

• 2.2 ; PPE Category 1

• By accelerating Overcurrent Protection Tripping Speed

Questions ?

Austin Energy’s Experience with AUD, Automated Utility Design

Software

Travis Vincent Sr. Electric Distribution Designer

Austin Energy

Travis Vincent

Experience with AUD, Automated Utility Design Software

Electric Distribution Designer Senior

About Austin Energy

• City of Austin Department with 1,700+ employees

• Generation, Transmission, & Distribution

• 485,204 meters

• 12,000+ miles of distribution and transmission line

• 437 square miles

• 84,000+ transformers

About Myself

• Electric Distribution Designer, Sr.

• 7 years of experience in Electric Distribution Design

• 10 years of experience working with AutoCAD

• B.S. Degree in Geographic Information Science, GIS

• 10 years of experience working with GIS software.

What is AUD?

AUD is a highly customizable electric design software plugin for AutoCAD that allows engineering, GIS, and data management functionality in an AutoCAD environment.

GISWork

ManagementSystem

Utility Standards

Engineering

AUD(AutoCAD)

Why We Chose AUD

•Design Difficulties Within the City of Austin• High Density: requires increased accuracy

• Fast Growth: requires increased efficiency

• City Codes: requires more information on design prints

•Design requirements at Austin Energy• Design Print Requirements: Construction, Engineering, Metering, etc.

• Standardization: Construction and design standards

•GIS/WMS Functionality • Import & Export to GE Electric Office (GIS)

• Import & Export to STORMS (WMS)

Headline Goes Here – Timeline Example

Project KickoffAutodesk

Austin Energy Hired IT SpecialistAUD Configuration

SBS Brought InIntegrations with GIS & WMS

Decision Made (AUD)

Further Enhancements & Bug FixesMore Designers For Testing

2014 2015 2016 2017 2018 2019

AUD Went Into Production (AE)Late 2016

SBS Became Exclusive Developer of AUDAutodesk no longer in the picture

Implemented Enhancements& Bug Fixes

Planning for UpgradeContinued Testing

Design Process

Customer

• Site Plan• AutoCAD File• Load Info

Designer

Utility Standards

GIS Data

Electric Design

Customer(Invoice & Civil

Plans)

Construction

Permitting

GIS Data

Utility Planning & Engineering

Austin Energy ‐ GIS

Work Environment

Design Layout

Design Print ‐ AUD

Challenges

•Software Challenges (bugs, slow, configuration issues)

•User/Designer Buy In

•GIS & Standards

•Purchasing Approval From City (AutoCAD to SBS)

What we like about AUD

• AUD works on top of AutoCAD which gives you the ability to use AutoCAD commands when designing.

• It is highly configurable and customizable.

• It has a built in “rule engine” which can be used for many things like material generation, validation, and analysis.

• It can be integrated with outside systems like GIS and WMS.

• Standardized output from all designers (North and South Design).

What we don’t like about AUD

• Our current 2016 version can be slow and cumbersome to use. The new version is suppose to be better.

• It requires AutoCAD training which can be time‐consuming and difficult.

• It is highly configurable and customizable.

What We’ve Learned

• We should have dedicated more resources for testing the product, including more designers.

• We should have focused on releasing and testing the necessary features and used a slower and more agile implementation of new features over time.

• We should have dedicated more resources for training.

• There are unintended consequences to enhancements.

Plans For The Future

•Upgrade to the Latest Version of AUD

• Implement Drawing Standards

•Continued Bug Fixes

• Focus on GIS Integration

Any Questions?

travis.vincent@austinenergy.com512‐505‐7614

Leveraging the Communication Network

Richard Huck Electrical Engineer

Xcel Energy

RMEL Conference 2019

Leverage Communication Networks

Richard Huck

1. Why is a Communication Network Needed for Distribution Automation (DA)?

2. Common Communications systems used for DA networks.

3. Communication Issues

Why is a Communication Network Needed for Distribution Automation?

? ?? ?

1. Reduces the response time in a power outage. Control room operators can direct line crews to outage areas quicker because they are more informed to what is going on with their Distribution automation networks, and they can find exactly where outages are occurring in their network.

2. More control of the Distribution Automation Assesses in the distribution network for switching and other operations.

3. Remote Monitoring of distribution automation equipment for maintenance saving drive time for maintenance crews.

Reduction in the response Time in a Power Outage in The DA Network

• Before power company's often relied on customers calling the power company to inform them of an outage.

• This often made things harder for control room operators as lineman had to physically search conductors and equipment in an area to determine where a issue exactly occurred and then repair the system.

Snap Shot of Small Area in Denver Metro Region of the Distribution Automation Network

SCADA Mate Switches and Reclosers in Boulder Mountains

Two SCADA Mate Switches in the Boulder Mountains

More control of the Distribution Automation Assesses

More Control of Distribution Automation

Common Communications Used1. Mesh Radio systems

2. Point to Point Radio Systems

3. Cellular Communications

4. Satellite Communications

Mesh radio system consist of a series of mesh clients, routers, and mesh gateways.

Clients would be mesh radios in distribution automation equipment such as recloser, a switch cabinet, a cap banks, a ATO’s, or a Regulator.

Routers/Repeaters used to route SCADA data from the Distribution automation equipment to a central head end radio system/gateway to the corporate network.

Gateways can be a central point where the SCADA date from the Distribution Automation comes back to the control center/ corporate network.

Snap Shot of Mesh Network

Advantages to a Mesh Network

Self Healing: If a repeater goes down another repeater or Mesh radio near by can take over for the bad repeater and route the SCADA data back to the control center.

There are several pathways ways for the SCADA data to get back to its Gateway or Headend radio.

Disadvantages to a Mesh Network

The more hops it takes to get back to it head end or gateway by repeaters adds latency to the radios system.

Five hopes could add several milli-seconds to its travel time back and forth from the DA device and its gate way to the control center/Corporate network

Point to Point CommunicationNetwork

Point to Point Network Can Have Several Point to Point Radios Pointing to a Central Head End Radio

Multi Point to Point Network

Point to Point Radio NetworkReduces time since their no repeaters to add latency to the radio system

You need to have a line of sight between the point to point radio systems

Point to point radios often require to be high off the ground

Disadvantages to a Point to Point NetworkIf Radio is lost in one of the point to point radios and you lose your SCADA Data for that part of the system.

Could be limited how high off the ground you can install the radio system

Cellular Network

Cellular Modem in Switch Cabinet

Advantages to a Cellular Network

1. You can have a back up SIM card in a cell modem in case one cellular network fails. Example AT&T and Verizon networks are available to use.

2. Do not need a repeater system to help get your signal back to your Corporate Network reducing latency.

3. Easy of install.

Disadvantages to a Cellular Network

1. Monthly bill for each cell modem which adds up quickly when you have hundreds of them in the field.

2. New Cellular Technologies comes out every few years and you may only get a few years out of a cell modem before you may have to replace it.

3. Cellular Coverage area can change

Satellite Systems

Satellite Systems Advantages

Great for Communications in remote areas where there is no cell coverage or it would be too expensive to install a mesh system to get back to the control center.

Satellite Systems DisadvantagesRain, Snow, and Dust fade

Need to have Line of Site to Satellite in Orbit

Monthly plans are much higher then a cellular modem

Latency since it has to go thousands of miles up to satellite in geo synchronous orbit and then back to a ground station on Earth to get back to corporate networks/control center

Network can have more than 750ms of Latency

Communication Issues That Have Occurred

1. Repeaters in Mesh Network have been remoted from field by mistake by Street Lighting, or power cords have been cut. Repeaters simply fail.

2. Batteries on repeaters need to be replaced every five years or they may fail to work in a power outage

3. Antennas on Switch cabinets and cap-banks that are low to the ground have and will be vandalized

4. New Construction has blocked line of site communications/ New buildings

Communication Issue That Have Occurred

5. High wind has moved satellite dishes off a few degrees and communications has been lost.

6. Batteries on repeaters go out and need to be replaced and repeaters will fail on a power outage.

7. Firewall were changed by IT and communications has been lost.

8. Directional antenna get knock out of alignment.

9. Security issues become more complex to keep an adversary out of the communication network

A great Communication Network for a SCADA System will require Multiple Systems

Multiple Point to Point systems as a back bone

Mesh radios used for metering and DA devices in field

Cellular used for locations outside of the Mesh and point to point system

Satellite System for remoted locations that do not have cellular coverage

Back up systems for emergencies

Any Questions?

Leadership – Consulting vs. Utility Discussion€¦ · 2? 3? 5? 7? ROI Fundamentals Who chose the...

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