leadership – consulting vs. utility discussion€¦ · 2? 3? 5? 7? roi fundamentals who chose the...
TRANSCRIPT
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:
Time 0 Year 1 Year 2 Year 3 Year 4 Year 5
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?
ROI FundamentalsProblem 1
At the end of:
Time 0 Year 1 Year 2 Year 3 Year 4 Year 5
Cash Flows (1,250,000) 400,000 400,000 400,000 400,000Cumulative Cash Flows
(1,250,000) (850,000) (450,000) (50,000) 350,000
ROI FundamentalsProblem 2
• 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:
Time 0 Year 1 Year 2 Year 3 Year 4 Year 5
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?
ROI FundamentalsProblem 3
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!!
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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
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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 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)
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ROI Fundamentals Example 2
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
ROI Fundamentals Example 2
NPV = Present Value of Future Cash Flows –Investment
NPV = ( 4,000 X 3.312) – 14,000 = -$ 750
ROI Fundamentals Example 2
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
Cumulative Cash Flows
(1,250,000)
NPV= ( 400,000 X 3.993 ) = $1,597,000 - $1,250,000 = $347,200
ROI Fundamentals Problem 4
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.
ROI FundamentalsProblem 4
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
Cumulative Cash Flows
(1,000,000)
ROI Fundamentals Problem 4
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
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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:
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Don’t Forget to NPV!
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Thank You
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Go Broncos
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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
Utility Emergency Reaction Panel
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
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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
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System Impacts
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North ForkElkhorn River
Norfolk, NE• March 2019• Building Evacuation
– Operations– Call Center
• Alternate Call Center Site Impacted– Limited Travel– Alternate Site
Limitations
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SubstationsNorfolk, NE
• Substation Flooded• Communications
Impact• Water Level in Control
Building and Impacted Equipment
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Columbus, NE• March 2019• Town Isolated• Alternate Call Center
– New Phone System– Call Coverage
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Columbus, NE
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March 2019 Road Closures
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• July 2019 Flash Flood• Building Evacuation
– Operations– Control Center
• Alternate Site Impacted• New AMI System
Kearney, NE
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• 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.
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Utility Emergency Reaction Panel
Travis Johnson Manager, Electric Distribution Standards
Xcel Energy
Presented byTravis Johnson
Manager, Electric Distribution Standards
2019 FALL RMELSTORM DAMAGELESSONS LEARNED
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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
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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
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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
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2017 – STORM JUPITERFIBERGLASS CROSSARM DAMAGE
• Failures– Conductor 4/0 ACSR Ultimate Tensile Strength – 8,300 lbs. force
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2017 – STORM JUPITERFIBERGLASS CROSSARM DAMAGE
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2017 – STORM JUPITERFIBERGLASS CROSSARM DAMAGE
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2016 STORM DAMAGE - CO
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UPLIFT ON POLES
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TRACKING ON FIBERGLASS ARM
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Utility Emergency Reaction Panel
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
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Emergency Response….
Plus…A Fatality or Serious Injury
• Large Number of Customers Out• Key Network Customers Out• Network Equipment/UG Cable Project Between Phases
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Incident Command
Media
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
ETR
Road Closures
Police/Fire
Current Loading
Scope and Replacement
Curious Citizens
Compromised Workforce
Initial Lessons Learned
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• 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.
© 2015 Eaton. All Rights Reserved..
Arc Flash Considerations with Distribution Overcurrent ProtectionTimothy Day, Sr. Applications Engineer OCT 2019
2© 2015 Eaton. All Rights Reserved..
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
3© 2015 Eaton. All Rights Reserved..
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
4© 2015 Eaton. All Rights Reserved..
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
5© 2015 Eaton. All Rights Reserved..
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
6© 2015 Eaton. All Rights Reserved..
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
7© 2015 Eaton. All Rights Reserved..
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
8© 2015 Eaton. All Rights Reserved..
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.
9© 2015 Eaton. All Rights Reserved..
• 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
10© 2015 Eaton. All Rights Reserved..
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
1 sec
• I.e., Incident Energy =
• The incident energy resulting in the onset of a second degree burn =
11© 2015 Eaton. All Rights Reserved..
NFPA Categories of PPEPPE Category Arc Rating Equipment
1 1.2 – 4
2 4 – 8
3 8 – 25
4 25 – 40
12© 2015 Eaton. All Rights Reserved..
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
13© 2015 Eaton. All Rights Reserved..
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
14© 2015 Eaton. All Rights Reserved..
Study Activity; Empirical Formulae, an intro.
15© 2015 Eaton. All Rights Reserved..
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
16© 2015 Eaton. All Rights Reserved..
Incident Energy Sensitivity: Arcing Time
I.E. (
peru
nit)
Arcing Time (sec)
• Calculated Incident Energy is directly related to fault duration time
17© 2015 Eaton. All Rights Reserved..
Incident Energy Sensitivity: Distance
I.E. (
peru
nit)
Distance (mm)
• Calculated Incident Energy is inversely related to the distance from the arc point to the person
18© 2015 Eaton. All Rights Reserved..
Incident Energy Sensitivity: Distance
I.E. (
% v
aria
tion)
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
19© 2015 Eaton. All Rights Reserved..
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
20© 2015 Eaton. All Rights Reserved..
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.
21© 2015 Eaton. All Rights Reserved..
time
Current240 A 600 A 1200 A
time
CurrentPick Up
TD 1
TD 3
TD 5
Reducing Incident Energy• Faster Clear Time = Lower Incident Energy
• Changes in Overcurrent Protection can reduce Clear Time.
Reducing Trip Threshold
Reducing Time Delay
22© 2015 Eaton. All Rights Reserved..
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
23© 2015 Eaton. All Rights Reserved..
Questions ?
Austin Energy’s Experience with AUD, Automated Utility Design
Software
Travis Vincent Sr. Electric Distribution Designer
Austin Energy
© 2019 Austin Energy
Austin Energy
Travis Vincent
Experience with AUD, Automated Utility Design Software
Electric Distribution Designer Senior
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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
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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.
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What is AUD?
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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)
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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)
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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
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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
AUD
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Austin Energy ‐ GIS
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Austin Energy ‐ GIS
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Work Environment
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Work Environment
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Design Layout
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Design Layout
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Design Print ‐ AUD
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Challenges
•Software Challenges (bugs, slow, configuration issues)
•User/Designer Buy In
•GIS & Standards
•Purchasing Approval From City (AutoCAD to SBS)
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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).
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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.
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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.
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Plans For The Future
•Upgrade to the Latest Version of AUD
• Implement Drawing Standards
•Continued Bug Fixes
• Focus on GIS Integration
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
Two SCADA Mate Switches in the Boulder Mountains
More control of the Distribution Automation Assesses
More control of the Distribution Automation Assesses
More control of the Distribution Automation Assesses
More control of the Distribution Automation Assesses
More Control of Distribution Automation
More Control of Distribution Automation
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
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?