Distribution Overhead and Underground Operations and Maintenance Conference

March 15-16, 2017 Denver Marriott South at Park Meadows Lone Tree, CO

Instructed by: Clifton Boop, Supervisor, Distribution Operations, Technical Support, Arizona Public Service Robert Ousley, Supervisor, Distribution Operations Center, Arizona Public Service Bill Menge, Director, SmartGrid, Kansas City Power & Light Joshua Jones, Director, T&D Standards Engineering, PacifiCorp Matt Wells, Operations Superintendent II, Colorado Springs Utilities David Tomczyszyn, Power System Consulting Engineer, Austin Energy Thomas Magee, Partner, Keller and Heckman LLP Sanket Adhikari, Supervisor, Transmission Operations Engineering, Arizona Public Service Mark Lesiw, Electric Standards Manager, Xcel Energy Bill Galloway, Standards Managing Engineer, Colorado Springs Utilities

WiFi Information Network: Marriott_Conference Password: RMEL2017

RMEL ~ 6855 S. Havana, Ste 430 ~ Centennial, CO 80112 ~ (303) 865-5544 ~ FAX: (303) 865-5548 ~ www.RMEL.org *Visit www.RMEL.org for the latest topic and speaker information. CONFERENCE Agenda Wednesday, 10:00 a.m. - 10:15 a.m. 1:00 p.m. - 2:45 p.m. products and services we Networking Break Distribution Vital Issues provide. PacifiCorp will be March 15, 2017 Roundtable discussing how they have adapted their business to Bring roundtable topics 10:15 a.m. - 11:15 a.m. provide distributed energy 8:30 a.m. - 9:15 a.m. for discussion and/or send Mobile Data & Workforce resource options and what Communicating Fault topics ahead of time to Management - A Discus- they are doing to optimize Indicators [email protected]. sion of Current Utility the integration of electric Roundtables offer a unique Clifton Boop, Supervisor, Deployments and Trends vehicles. forum for peer-to-peer shar- Distribution Operations, Joshua Jones, Director, T&D ing of experiences, critical Technical Support, Arizona Standards Engineering, issues and expertise. The 3:45 p.m. - 4:30 p.m. Public Service PacifiCorp roundtable is a discussion APS Solar Partner Robert Ousley, Supervisor, Matt Wells, Operations group, open only to RMEL Program Distribution Operations Superintendent II, Colorado Center, Arizona Public Service members. Discussion is Sanket Adhikari, Supervisor, Springs Utilities Transmission Operations This presentation will cover based on topics brought by Robert Ousley, Supervisor, Engineering, Arizona Public utilization of communicating attendees. Roundtables are Distribution Operations Service Company fault indicators on the APS focused on the open discus- Center, Arizona Public Service sion period and provide Increasing levels of rooftop Distribution System. The David Tomczyszyn, Power presentation will include each attendee the oppor- PV penetration on distribu- System Consulting Engineer, tunity for participation and tion feeders in APS’s service initial experience and use of Austin Energy CFI’s in addition to updates dialogue on their particular territory have introduced Many utilities are navigating and most valuable strategy issue. Roundtables are various challenges in the Dis- through the best practices and locations we have found held in conjunction with a tribution System. Through to maximize on mobile work- for them. We will cover the conference and many topics Solar Partner Program force management. Attend- strengths and weaknesses presented at the conference (SPP), APS is getting deeper ees will participate in open we have discovered and con- are discussed further in understanding of these chal- conversation regarding their tinue to learn with deploying the roundtable setting. The lenges and is researching current utility deployments approximately 800+ devices roundtable is a good oppor- the use of the technologies and trends. onto our system. tunity to share experiences, like residential advanced troubleshoot problems inverters and feeder level 9:15 a.m. 10:00 a.m. 11:15 a.m. - Noon and network with peers in energy storage to address Small Cell Attachments to a smaller, informal setting. these challenges. As part of Distribution SCADA Utility Poles Each participant is offered SPP, APS installed more than “Lite” without a SCADA Thomas Magee, Partner, a chance to pose questions 1500 utility owned residen- System and Automatic and share information. All tial rooftop PV systems for Reconfiguration of Keller and Heckman LLP This presentation will attendees are encouraged to total of 10MW, all equipped Distribution System After bring issues for discussion with smart inverters and a Fault discuss the regulatory and operational issues pertaining and materials for sharing. controlled from a centralized Bill Menge, Director, to small cell wireless at- control system. In addition, SmartGrid, Kansas City Power tachments to electric utility 2:45 p.m. - 3:00 p.m. APS has also installed two & Light poles, and explain provisions Networking Break 2MWhr battery energy stor- As part a “fork-lift” upgrade utility pole owners can use age systems on two distribu- of the OMS System, KCP&L to protect themselves. 3:00 p.m. - 3:45 p.m. tion feeders. APS has been integrated monitoring and conducting an 18 month long PacifiCorp’s Integration control of Distribution 12:00 p.m. - 1:00 p.m. research on these technolo- Automation (DA) equipment of Distributed Energy gies in collaboration with directly into the OMS. Previ- Networking Lunch Resources and Electric Electric Power Research ously portions of the DA Vehicles Institute (EPRI). This pre- system were integrated into Joshua Jones, Director, T&D sentation will inform about the EMS SCADA system with Standards Engineering, the design and architecture other components operated PacifiCorp of the program, challenges via a web-based platform. The electric utility industry encountered, innovative so- Now Operators receive is changing and in order to lutions implemented and the alarms and can control DA provide the best service for initial research findings. equipment DIRECTLY from our customers the traditional the OMS without having to electric utility industry must 4:30 p.m. - 5:30 p.m. login to other systems. This change with it. People dramatically reduced the interact with our product in Networking Hour number and complexity of much different ways than the interfaces required for they did in the past and now daily operations. expect to see options in the Distribution Operations and Maintenance Conference Industry Best Practices for Emerging Technologies. Developing Technologies and Industry Practices as it Evolves Around Us

to Light Emitting Diode Thursday, (LED) technology. LED’s use March 16, 2017 significantly less energy than traditional lighting and typi- 8:00 a.m. - 9:30 a.m. cally have much longer use- ful life spans. While making Distribution Vital Issues the switch to LED’s seems to Roundtable be a “no brainer”, as is often Bring roundtable topics the case, the upgrades to for discussion and/or send LED’s can get difficult once a topics ahead of time to utility reviews the details of [email protected]. the numerous LED offerings. For example, recently the 9:30 a.m. - 9:45 a.m. American Medical Associa- Networking Break tion issued a report claiming there may be health and en- 9:45 a.m. - 10:00 a.m. vironmental concerns associ- Attendee Announcements ated with certain LED’s. This presentation will detail those Any registered attendee and other issues utilities is invited to make a short moving to LED streetlights announcement on their com- should consider. pany, new products, technologies or informational updates. Announcements 10:45 a.m. - 11:30 a.m. may include showing a 2017 NESC Arc Flash product sample but not vid- Update and Methods to eos and power point slides. Reduce Exposure Without Thank You RMEL Distribution Please limit announcement Increasing PPE Committee to 5 minutes. Bill Galloway, Standards Managing Engineer, Colorado CHAIR Brent Gerling Springs Utilities 10:00-10:45 a.m. Bill Galloway Independence Power & Light David Tomczyszyn, Power Making the Move to LED Colorado Springs Utilities Distribution Engineer System Consulting Engineer, Lighting, What Should Standards Managing Engi- Austin Energy You Be Thinking About? neer Joshua Jones An overview of the Arc Flash Mark Lesiw, Electric PacifiCorp and PPE requirement chang- Standards Manager, Xcel VICE CHAIR Director, T&D Standards es affecting utilities in the Energy Ebi Kazemi Engineering 2017 NESC. And examples Black Hills Corporation Utilities across the United of how utilities are reducing Manager, Engineering Mark Lesiw States have been upgrad- potential arc flash exposure Xcel Energy ing traditional streetlights to their employees without Andy Alexander Electric Standards Manager increasing their PPE. Kansas City Power & Light Manager T&D Central Design Bryce Priest SRP John Cole Sr. Engineer Arizona Public Service Section Leader, Operations/ David Tomczyszyn Maintenance Austin Energy Power System Consulting Engineer

The RMEL Distribution Committee plans all RMEL Distribution events. If you’d like to send information to the committee, email James Sakamoto at [email protected].

Communicating Fault Indicators

Clifton Boop Supervisor, Distribution Operations, Technical Support Arizona Public Service

Robert Ousley Supervisor, Distribution Operations Center Arizona Public Service

Communicating Fault Indicators

Arizona Public Service

Clifton Boop Robert Ousley Supervisor DOC Technical Support Supervisor, DOC Arizona Public Service Company Transmission & Distribution Overview

• APS Customers – 1.2 million customers – 11 out of 15 counties in Arizona – 35,000 square mile service territory – 6th largest service territory out of 150 investor- owned utility operating companies reported by EEI*

• Transmission and Distribution Employees – 394 Distribution Operations & Maintenance – 236 Transmission Operations & Maintenance – 316 Construction – 295 Statewide Region – 116 Safety & Performance Excellence – 148 Engineering – 1,505 Total T&D employees

• Equipment – 34,601 Residential Solar systems installed (7/2015) • 244 MWs residential PV/ 263 MWs Commercial PV – 6,000 transmission miles – 29,000 distribution miles – 521,000 poles – 302,000 transformers – 419 substations – 1,300+ overhead and underground distribution feeders – 1,200+ smart circuit devices deployed on over 250 feeders by 2015; devices include Communicating Fault indicators, automated switches, network protectors, volt/VAR control, Substation health monitors, etc. *2013 data

2 Why the Grid Must Change

Traditional Flexible Grid Grid

1-Way Power Flow 2-Way Power Flow

Seasonal Voltage Dynamic Voltage Settings Variability

Renewable Base Load Generation Intermittency

Sizing for Increased Planning Criteria Renewables

Load/Generation Load/Generation Matching Mismatch

3 Drivers For Change

Energy Independence, Distributed Energy, Utility Scale Solar, Electric Vehicles, Microgrids, and Demand Response

Smart Phone Applications, Opt-in Transforming Notifications, Home Energy Marketplace Microprocessors, Advanced Management, Self-Service, Service Applications, Battery Storage, Wireless Options, and Customized Offerings Devices, and Cloud Computing

Customer/ Consumer Technology Needs and Advancement Expectations Need For Change

Less Customer Outages, Reduced Restoration Times, Improved Power Increased Asset Life, Improved Quality, and Increased Outage Reliability Asset Capacity Factors, Reduced Losses, Communications Performance Utilization Improved Power Factors, and Increased System Efficiencies

4 APS 5-Year Technology Deployment Plan

Integrated Volt/VAR Control (IVVC) Synchrophasors 991 Devices on 153 Feeders Network Protectors 15 Devices 120 Devices

Energy Management Integrated Operating System (EMS) Upgrades Center with Advanced Distribution AMI Management System 1.2 Million Meters Deployed

Transformer Load Management Tool Renewable Feeder Tool Fire Mitigation Expulsion Limiting Fuses Supervisory Controlled Switches 710 Devices on 284 Feeders

Voltage Visualization Substation Health Monitoring Communicating Fault Indicators (CFI) 579 Devices at 142 Substations 2,607 Devices on 568 Feeders

5 STEPS TAKEN TO SUPPORT NEW TECHNOLOGY

• Metro & State area Operation Centers integrated from 5 DOC’s into one centralized Operation Center. (2014) • Implemented ADMS January 2017 • Best in Class Initiative (ongoing) • Data Analytics Overhead/Underground CFI’s

Construction & Installation

• The GridAdvisor Series II smart sensor consists of a sensor unit with an integral dual LED indicator powered by a rechargeable Lithium phosphate battery. Rugged solid-state construction ensures dependability and accuracy. • Installation is quick and easy. No special tools are required. The sensor unit itself features a clamping mechanism design that allows easy snap-on connection to the live conductor with the use of a single hotstick. • APS requirement is a minimum of 10 amps per phase continuous. • Coordination between Engineer & Load Management Specialist /Planner to select device locations. • Feeders and locations selected based off reliability data, geographic accessibility, length, and some placed to compliment other SMG device locations.

Benefits

• The estimated benefit is derived from the following areas: – Reduced Distribution Operations & Maintenance Cost – Reduced Sustained Outages* – Reduced Restoration Cost – Reduced Lost Energy Revenue – Reduced Vehicle Safety Events – Reduced Customer Outage Minutes* – Narrowed patrol area after momentary outages* – Increased confidence that troubleshooter will find cause * Visualization

• Grid Advisor – SG Net • CFI Application – Pi Processbook • Pi Coresight SG Net – Grid Advisor CFI Application – Pi Processbook Active loss of current

Pi Coresight Pi Coresight Current State

Locations: • Total of 1152 devices at approximately 392 different sites. (mixture of 1, 2, & 3-ph sites)

• Installing in conjunction with SCADA Controlled Switches & other SG Devices. Lessons Learned

• Location selection for battery charging • Seasonal load areas • Battery issues due to outages or line construction in area. • Ease of visualization for Operations Center Battery Replacement Questions?

Distribution SCADA “Lite” without a SCADA System and Automatic Reconfiguration of Distribution System After a Fault

Bill Menge Director, SmartGrid Kansas City Power & Light

RMEL Distribution Operations and Maintenance Conference March 15-16, 2017 Denver, Colorado

How KCP&L Created a Distribution SCADA-Lite without a Distribution SCADA System

Bill Menge Smart Grid Director Kansas City Power & Light KCP&L – Midsize Investor Owned Electric Utility

Key Statistics Customers 830,000 Geography 18,000 sq mi Missouri & Kansas Employees 3,000+ Generation 6,600 MW Distribution Subs 315 Distribution Circuits 1600

2 KCP&L – Midsize Investor Owned Electric Utility

Key Statistics Customers 830,000 Geography 18,000 sq mi Missouri & Kansas Employees 3,000+ Generation 6,600 MW Distribution Subs 315 Distribution Circuits 1600

3 KCP&L Capacitor Communications Timeline (significant to DA history)

Tropos (12-14)

~90% of capacitors are automated, reducing FlexNet (2014) need for time-based maintenance. Telemetric Public Cellular (Analog, 2G, 3G)

Cellnet 2-Way (ends 2015)

Timeline Energyline/ 2-Way Cap Winmon Near Unity TC012 TC032 S-Grid CBC-8000 Cellnet AMR Intellicap Win Mon Comms Query Tool KCPL PF Control Control VVC Demo Control Controls 199395 93 95 95 97 02-08 03 10 14 15

Remote Settings - Tuning Key Fixed Bank Automation Communications Pink text is 1999 SmartGrid Demo Hawthorn Explodes Functionality Dynamic Voltage Control

GMO Automation

VVC Demo

OMS Integ

4 KCPL DA Device Population

Capacitors – 2511 Reclosers - 120 Intellirupter- 12 Regulators– 12 FCI – 268 . Cellnet 418 . All Cellular . All Cellular . All Cellular . All Cellular . Cellular 1733 . Flexnet 360

UG Network - 134 Vista – 13 Trident – 1 TVM Voltage 50 CO & DVC – 203 Buses . All Cellular . All Cellular . All Cellular Monitor – 122 . EMS Comms (SF6 in Vaults) (solid Dielectric in vault) . All Cellular (50 CO is remote enabling of fast trips. DVC is Voltage Reduction)

Other - ~20 Total Automated Devices: ~3200 (not including 50 CO and DVC)

5 KCPL DA Devices w/ Sensus Communications

Capacitors – 2511 Reclosers - 120 Intellirupter- 12 Regulators– 12 FCI – 268 . Cellnet 418 . All Cellular . All Cellular . All Cellular . All Cellular . Cellular 1733 . Flexnet 360

Other - ~20 Total Automated Devices: ~3200 (not including 50 CO and DVC)

6 KCPL DA Communications

Three DA Communications Infrastructures prior to Project

. Cellnet (retired 8/15/2015) . Sensus (formerly Telemetric) Public Cellular . Sensus Flexnet – Private Cellular

TROPOS wireless mesh was piloted in a SmartGrid Demo, but not selected for enterprise deployment.

7 KCPL DA Communications History

. Various one-way pager pilots – 1980’s . CellNet early 1990’s . Metricom/UtiliNet radios – mid 1990’s . Commercial Analog Radio – rural applic 2001 . GPRS 2G Public Cellular – 2006 (Retires 2016) . GPRS 3G Public Cellular – 2011 . TROPOS – Piloted in SmartGrid Demonstration . FlexNet – early applications – 2014

In-use today. 8 KCPL Distribution Platform Consolidation

Sensus Sensus Sensus Winmon Power Auto. Email (Cellnet DA) EMS OMS Vista Contol Notification

DSO Dispatcher Systems Prior to OMS-Phase-II D-SCADA-Lite

Separate Interfaces complicate life in the DSO (Distribution System Operations).

Operators did NOT get consistent look & feel

9 KCPL Distribution Platform Consolidation

EMS OMS

DSO Dispatcher Systems TODAY with D-SCADA-Lite

 Winmon Retired 8/15/2015  Sensus Website still available as a Backup (Heavy Engr use)  Desire to Integrate EMS to OMS for Breaker Status

Now Operators get consistent look & feel

10 Oracle NMS Viewer (DSCADA-Lite)

Point & Click Screens within the OMS Viewer

Operators get consistent look & feel 11 Legacy Integration to EMS SCADA

EMS Replaced in 2015 Retired in 2015

NO DA in SCADA 12 Pre-project State - 2014

Flex v1 SXG = FLEX v1 Sensus ScadaXchange PV I wish I could see and Aeris (PowerVista) operate all the DA SXG Devices thru my OMS without having to go to 3G-CDMA ATT Secure VPN EMS SCADA or Sensus Internet via KCPL DNP 3.0 Web. Single Sign-on (ScadaXChange)

2G 3G KCPL DNP Proxy Server PowerVista EMS (SCADA) Web Apps (“Bow Box”) KCPL SCADA

Legacy OMS is COMPLETELY separated from all DA. Operating data has to be entered manually to OMS. 13 Integrating DA Devices into New OMS (SCADA-Lite)

Oracle Network Manager System – KCPL OMS DNP3

ICCP

Sensus Cloud Platform Including SCADA-Xchange – LiveData RTI Operates as Manages the FAN Real-time OT Centric Middleware Platform – reduces OT integration time.

User-friendly Config tools. 14 Current State – Live in 2Q 2015

I’m so happy. I run OMS Flex v1 and SCADA-Lite from one SXG = FLEX v1 Sensus ScadaXchange screen & I don’t care how PV it gets here. Aeris (PowerVista) SXG

3G-CDMA ATT Secure VPN Internet via KCPL DNP 3.0 KCPL OMS (ScadaXChange) Single Sign-on (Operations)

2G 3G Live Data KCPL OMS PowerVista RTI Platform (Oracle NMS) OT MessageLive Data Bus/Server (Not a SCADA System Web Apps (Redundant) ICCP ) (Mostly Engineering)

Now Operators get consistent look & feel. OMS tracks the DA operating data. 15 OMS DNP Point List/Testing – for DSO

Total DSO Required Total NMS Testing Device Device Type AI DI DO AI DI SCADA Testing Resources Points Alarming Points Availability

TC032 27 4 17 6 2 0 2 DA, OMS, SE, LD, OR* Y ETI-Relay Network 22 5 11 6 3 2 1 DA, OMS, SE, LD, OR, RL, UD Y protector TC012 10 5 5 0 0 0 0 DA, OMS, SE LD, OR Y Copper 34kv 64 17 31 16 2 0 2 DA, OMS, SE, LD, OR, RL Y Recloser LS Copper 34kv 76 23 31 16 2 0 2 DA, OMS, SE, LD, OR, RL Y Recloser LS2 TVM3 11 10 1 0 0 0 0 DA, OMS, SE LD, OR Y INT120S Cap 29 6 13 10 0 0 0 DA, OMS, SE LD, OR Y Control INT120 VARN Cap 18 3 10 5 0 0 0 DA, OMS, SE LD, OR Y Control T600/T646 (FCI) 3 1 2 0 0 0 0 DA, OMS, SE LD, OR Y MJXL 7 0 4 3 0 0 0 DA, OMS, SE LD, OR ?? EL1000N Cap 19 6 7 6 0 0 0 DA, OMS, SE LD, OR Y Control

SC VistaGear 16 0 12 4 2 0 2 DA, OMS, SE LD, OR, RL ??

Pulse Recloser 38 20 14 4 4 0 4 DA, OMS, SE LD, OR, RL ??

Nule ACR 31 10 17 4 2 0 2 DA, OMS, SE LD, OR, RL ??

Nule ACO 27 9 9 9 3 0 3 DA, OMS, SE LD, OR, RL ??

16 Control of Field Devices from OMS

Operators get consistent look & feel

17 OMS Alarming in Oracle NMS

Operators get consistent look & feel 18 Real Time Integration – Many Flexible Options

Option B Third-Party SCADA System Option B.3 Option B.1

IED Sensus DNP/TCP/IP Secure VPN Option B.2 FCI SCADA_Xchange Server Option A DA Live Data DA Device

Server/OTMB ICCP

RTP CAP DNP/TCP/IP TCP/IP control Smart IED Recloser Option C KCPL OMS D-SCADA

19 KCPL Potential Long Range Roadmap

Y Y Z Z X Vendor X Headend or Web Integrate to End Devices X S-Slave FLEX V2

X FLEX V1 Integrate to System(s) Flex v1 S-Master (or v2) Sensus Power Vista AC v3.? (Automation Components Control) ATT left off to save SXG nG space

Internet 2G 3G 4G No 2G in AC AC LTE Web Apps Web Apps are 3G Via Repoint powerful tool for ATT Sunset ~2018 4G LTE Engineering and Available 2015 KCPL OMS Live Data are a built-in (Oracle NMS) Live(Redundant) Data backup system. (Not a SCADA System)

I’m extremely happy. I run OMS and SCADA-Lite from one terminal/screen & I don’t have to care how it gets here…… AND Engineering can bring in devices from all kinds of vendors for amazing operational functionality – usually without KCPL OMS bothering KCPL-IT. (Operations) 20 I Love D-SCADA Lite!! – Why would I need to buy a D-Scada system? Why Use Middleware (LiveData RTI)?

LiveData’s RTI Platform/OT Message Bus . Real-time OT centric middleware platform . Ensure the protection of  Life, equipment, environment . Supports many utility protocols including:  ICCP, DNP3, modbus, OPC, Web Services . Python support, 50+ built-in data filters and templating . Faster OT system integrations  Less risk, less cost, less one-off custom point-to-point solutions  User-friendly Configuration tools . Future-proof system integration . More tolerant of lossy and messy radio networks

21 Middleware ConfigTool

. Point and click ‒ easy dataflow configuration . Simplifies the complexity of OT integration (use of templates) . Robust change management for lifecycle control 22 Middleware Config on KCP&L Project

. 90,000 data points  Reduced to 30 templates

. Significant cost/time savings relative to custom interface

. LiveData actively manages Sensus/Oracle interface

. Data flow 138 feet by 8 feet at full scale

23 23 Questions

Bill Menge Smart Grid Director Kansas City Power & Light 816-245-3926 [email protected]

A special Thank You to Tianling Wu, KCP&L DA Engineering – KCP&L’s project architect.

Small Cell Attachments to Utility Poles

Thomas Magee Partner Keller and Heckman LLP

Small Cell Attachments to Utility Poles

March 15, 2017 Thomas B. Magee, Partner Keller and Heckman LLP Washington, DC Office 202.434.4128 [email protected]

. What Are Small Cells and Why Are We Going to See A Lot More of Them? . Regulation of Small Cell Attachments . Contract/Rate/Construction Standard Issues

. Mobile Wireless Data Consumption to Increase Six Fold by 2022 . FCC Estimates New Small Cell Antenna Construction Sites • 100,000 to 150,000 by end of 2018 • 455,000 by 2020 • Nearly 800,000 by 2026 . Estimated 50% or More On Utility Poles

. Fiber Attached to Every Pole . Every 6-15 Poles – “Node” Pole: • Antenna • 2.5 Foot Cabinet • Wire Connecting Cabinet to Antenna • Electric Distribution Panel • 120V, 20A GFCI Work Receptacle • Electric Meter • Work Light

. 47 U.S.C. 224 . FCC Regulates Attachments to IOU Poles in 30 States • State Regulation in 20 and Wash, D.C. • Some Regulate Co-op & Muni Poles . FCC Regulations Often Followed by States

. Applies to Cable & Telecom Cos. . Wireless Telecom Qualifies . Non-discriminatory Access to Poles, Ducts, Conduits and Rights-of-Way . Regulated Rates . Can Deny Access for Capacity, Safety, Reliability & Engineering Reasons

. Distribution Poles . Not Street Light-Only Poles . Not Street Light Arms . Not Transmission-Only Towers • But w/Distribution Under-build?

. CMRS Providers . DAS Companies . WISPS . Infrastructure-Only Attachers . Cable Company WiFi/Wireless Broadband

November 2016 Mobilitie Petition Claims Local Gov’t Site Approval Slow and Expensive December 2016 FCC Asks for Comments on How to Streamline Local Gov’t Review

. Legislation Introduced 17 States (so far) . Limit Local Gov’t Review Time and ROW Access Fees . Some Set Attachment Rates to Muni Poles . Two Would Have Affected Co-op Poles . Most Envision Wireless Cos. Installing Own Poles

. Primary Voltage Poles – Pole Top Access? . Poles with Reclosers, Sectionalizers, Capacitors, Regulators, Multiple Risers, Other Large Equipment? . Truck Accessible . Adequate Strength/Space for Installation? . Maintain Climbing Space . Grounded Antenna . Equipment On/Off Pole?

. Maximum Permissible Exposure Compliance? . Interference With Utility Wireless? . Certification by Telecom Engineer . On/Off Switch . Posting of RF Signs . Citizen Opposition

. FCC Requires Cost-Based . California PUC Formula . Pole Top Different? . What if Replace Pole?

. Application Process, Identification and Approval . Installation and Maintenance • Radiofrequency Interference and Exposure Testing, Mitigation, Notifications and Certification . Authorized Uses and Access . Landowner/Government Authorizations . Attachment Fees and Penalties . Indemnifications and Other Safeguards

Thomas B. Magee, Partner Keller and Heckman LLP Washington, DC Office 202.434.4128 [email protected]

Washington, DC • Brussels • San Francisco • Shanghai • Paris

PacifiCorp’s Integration of Distributed Energy Resources and Electric Vehicles

Joshua Jones Director, T&D Standards Engineering PacifiCorp

A Grid In Transition

Joshua Jones, PE Director, T&D Standards About PacifiCorp

• Customers 1.8 million • Employees 5,700 • Territory 143,000 sq. mi. • Distribution 64,000 Line Miles • Transmission 16,500 Line Miles • Generation 72 Plants 10,894 MW Capacity

2 A Century of Service

• Salt Lake City was the fifth city in the world to have central station electricity behind only London, New York City, San Francisco and Cleveland.

• Rocky Mountain Power dates back to 1881.

• PacifiCorp is the combination of 368 companies

3 Primary Voltages

• 2.4kV • 12.47kV • 34.5kV • 138kV • 4.16kv • 13.2kV • 46kV • 161kV • 7.2kV • 13.8kV • 57kV • 230kV • 11.5kV • 20.8kV • 69kV • 345kV • 12kV • 24.94kV • 115kV • 500kV

That’s 20 primary supply voltages.

4 Total Responsibility

• Generation – Coal/Gas/Wind/Solar/Geothermal • Substation • Distribution – Overhead • NESC and GO95 Network System – Underground • NESC and GO128 – Network • Transmission – Overhead – Underground • Communications

5 The Transition

Efficient Effective • How fast can you build a substation / • How to defer investments with transmission line / distribution line distributed energy resources • How to buy the hardware at the best • How to find good manufacturers in a price global economy • How to prevent customer impact from • How do we work with our customers motor starts, flicker, power quality to avoid impacts. Our customers need to work with us! What do our customers value and how can we provide that?

6 Improving Customer Reliability

Visual Indication Directional Indication

Communicating Improving Customer Reliability

8 Improving Customer Reliability

Loss of Current

No Alarm

Recloser Fault Indicator

9 Integrating Distributed Generation

10 Customer Rooftop Generation

11 Handling Reverse Power Flow

• Without distributed energy resources – Energy flows from utility to the customer

• With distributed energy resources – Energy flows to and from the customer depending on the time of day and their consumption

• Voltage control is independent of current flow

12 12 Maintain Customers Voltage

• Service voltage bandwidth = ANSI Range A – Nominal +/-5% for secondary delivery

126

Line regulator 120 Voltage

114

Length

13 Voltage Control Modes

14 Integrating Distributed Generation

Traditional Regulator Control – Single phase controller – Available reverse power flows would not allow regulation in the reverse mode – Regulation is blocked during reverse power flow Co-generation Regulator Controls – Source and load PTs are required – Allows regulation in the reverse power flow: • Block • Regulate • Line drop compensation • Adjust bands 15 Bi-directional Reclosers

Line Reclosers – Fault settings • Forward • Reverse – Load/source voltage sensors – Communication enabled

Generation Reclosers – Transfer-trip capabilities – Generation/load shedding – Dead-line check

16 Improve Reliability / Storage

17 Improve Reliability / Storage

• Current subdivision standard is a 75kVA serving 8-10 homes

• 5% of new transformers installed are ideally design to accept this device

• Requires fire department approval

18 Battery and Storage

19 Evolution of Electric Vehicles

20 Improve Air Quality

21 CO2 Emission by Sector

22 Integrating Electric Vehicles

• EV integration • Understand user behavior • Build infrastructure to meet demand • Improve air quality

23 Integrating Electric Vehicles

24 Integrating Electric Vehicles

• Design and Develop Screening Locations – Residential – Commercial / Transit Corridor – Electric Bus Integration • Modeling and Testing – Transformer loading – Voltage regulation – Power quality effects • Develop Utility Best Practices – Screening criteria – Build new construction standards – Reduce infrastructure requirements

25 Delivering Our Core Business

• Declining US product sales • Overseas production • Product testing – Approval – Post contract – Product failure resolution • How do we make changes in a declining market?

26 Berkshire Hathaway Energy

27 Berkshire Hathaway Energy Standards

• Develop common specifications • Utilize the products the same way • Increase market volume • Reduce cost and drive product development

28 Questions?

APS Solar Partner Program

Sanket Adhikari Supervisor, Transmission Operations Engineering Arizona Public Service

APS – Solar Partner Program

Sanket Adhikari Supervisor, Transmission Operations Engineering, Arizona Public Service Company (APS), Phoenix, AZ

RMEL’s Distribution Overhead and Underground Operations and Maintenance Conference, Denver, CO 03/15/2017 APS - Company Background

• Arizona’s largest and longest serving utility – since 1886 • Service Territory – 11 out of 15 counties – 1.2 Million Customers (89% residential) – 34,646 square miles • Peak Demand ~ 7300MW in June 2016 • More than 1GW of Solar Capacity - 4th in the nation – 50% of solar portfolio is distributed – Pioneer in solar research since 1970s

2 Project Overview

COMMUNICATIONS • Approx. 1600 APS owned systems

with smart inverters; total 10MW EQUIPMENT DEFFERAL • $30 bill credit for customers, 20 year lease, connected on utility side INVERTER CONTROL & FUNCTIONALITY • 2, 2MWh energy storage systems on two feeders STRESS & VOLTAGE MANAGEMENT • 21 research questions; extensive research for 18 months ENERGY STORAGE

1 4 3 6 5 2 Smart Inverters

SMA inverters in SPP  Sunny Boy 4000TL-US-22 (4kW)  Sunny Boy 6000TL-US-22 (6kW)  Sunny Boy 7700TL-US-22 (7.7kW)

4 SPP - Road to Research

• Research •Inverter questions selection • Technical •UL analysis certification • Feeder • Technology Selection Feeders Inverter know-how Research • PQM installs • Training and testing • Analysis and reporting

Control Comm • Selection and • STAR lab architecture • Cellular path • IT interfaces •AMI path • Visualization Milestones

• Use cases – Feb 2015 • Feeders identified – Apr 2015 • Inverter selected – Apr 2015 • Research questions – Jun 2015 • Control system selected – Jul 2015 • STAR lab set-up – Aug 2015 • Control system complete – Jan 2016 • Test Plan Finalized – Feb 2016 • 18 PQMs installed – Feb 2016 • UL1741-SA certification – Mar 2016 • Research began – Apr 2016 • Inverter on AMI – Nov 2016 • Batteries on the field – Dec 2016 • Fourth Research report – Dec 2016 50 2 1600+ 11 Inverter Communication Installations Smart Functions Registers Paths and Protocols

1 2 1100 500 Centralized Battery Energy AMI Radios Cell Modems Controller Storage Systems

21 21 18 15+ Power Quality Research Month Long Conferences Monitors Questions Research and Publications

SPP in Numbers Field Measurements

PQ – 1 second PQ – 1 minute Inverters – 5 minute AMI – Hourly

Voltage Voltage Flicker DC Voltage/Current Energy Current Voltage THD AC Voltage/Current Consumption

Power Current THD Input Power PV Energy Reactive Power Sequence Currents Output Power Production Power Factor Phase Imbalance Reactive Power Avg Voltage Frequency Total Energy Inverter Status Max Voltage Fast, Accurate Fast, Coarse Data Slow Few Locations Several Locations Many Locations

PQ monitors also capture cycle-level data for transient events

8 Challenges/Surprises

• Inverters – Technology and standards – Remote firmware updates • Monitoring and Control – Systems not readily available – Different devices and protocols • Communication Selected – Installation and integration Functions – Limited, non-standard protocols • Research Day Type Season Test – Monitoring equipment install Condition – Data management and testing Grouping Operations Method Thank you!

Making the Move to LED Lighting, What Should You Be Thinking About?

Mark Lesiw Electric Standards Manager Xcel Energy

WHAT TO THINK ABOUT WHEN THINKING ABOUT LED’S

Mark Lesiw P.E. PROS AND CONS

• Benefits of LED’s – Energy Efficiency – Maintenance – Illumination Control

• Challenges of LED’s – Too Many Choices? – Potential Health Concerns? – Big Projects? – Timing – What about the next thing?

2 LIGHTING BASICS

• What is color temperature?

3 CORRELATED COLOR TEMPERATURE (CCT) AND COLOR RENDERING INDEX (CRI)

Clear sky 15,000K-27,000K Light Source CCT (K) Avg CRI Low Pressure Sodium 1700 0% LCD Screen High Pressure Sodium 2000 20 10,500K Incandescent 2700 100 White LED 2700 70 Metal Halide 6200K White LED 3000 70 White LED 4000 70 Fluorescent 5000K White LED 5700 70 Mercury Vapor-Coated 4000 45 Moonlight Mercury Vapor-Clear 6500 15 4100K Metal Halide Coated 3000 70 Incandescent Metal Halide Clear 4000 60 2700K Fluorescent 3000 80 Fluorescent 4000 80 Candle flame 1700k

4 DRAMATIC DIFFERENCE

5 COLOR TEMPERATURE WARNINGS

• American Medical Association

6 AMA REPORT CONCERNS

Concern with short-wavelength Physical stimulus characteristics emission from LED • Spectrum • Blue light hazard • Amount – Extended duration to retina • Duration • Glare, both disability and • Spatial distribution discomfort • Timing • Melatonin suppression • Polarization – Exposure duration leading up to sleep • Circadian disruption – Darkness while sleeping

Issue with short-wavelength In- Ga-N LED 3000K or 4000K CCT Wavelength (nm) 7 BLUE LIGHT

Vague Luminous Blue Light Light Source Flux (lm) CCT (K) Content % Moonlight-Full 1000 4000 30% Low Pressure Sodium 1000 1700 0% High Pressure Sodium 1000 2000 10% Incandescent 1000 2700 12% White LED 1000 2700 18% White LED 1000 3000 22% White LED 1000 4000 30% White LED 1000 5700 40% Mercury Vapor-Coated 1000 4000 30% Mercury Vapor-Clear 1000 6500 45% Metal Halide Coated 1000 3000 24% Metal Halide Clear 1000 4000 35% Fluorescent 1000 3000 20% Fluorescent 1000 4000 30%

LSPDD: Light Spectral Power Distribution Database http://galileo.graphycs.cegepsherbrooke.qc.CA/app/en/home

8 WORKING WITH MUNICIPALITIES

• What is their goal? – Cost savings – Reliability – Aesthetics

9 ACCEPTANCE TESTING

• Light Performance • Radio Frequency Interference • Mechanical Issues

10 WHAT’S NEXT: SMALL CELL

11 WHAT’S NEXT: SMART STREETLIGHTS

• Parking • Surveillance • Traffic Optimization • Lighting Control • Gunshot Detection • Road Maintenance • Environmental Analysis

12 Questions ?

2017 NESC Arc Flash Update and Methods to Reduce Exposure Without Increasing PPE

Bill Galloway Standards Managing Engineer Colorado Springs Utilities

David Tomczyszyn Power System Consulting Engineer Austin Energy

Distribution Conference March 16, 2017

Austin Energy and Colorado Spring’s Utilities NESC Update to Arc Flash Protection

Presented By: Bill Galloway (CSU) & David Tomczyszyn (AE) 1 NESC 2017 Update to Arc Flash Safety - Outline 1. NESC 2017 Changes 2. Reducing Exposure to Arc Flash with Engineering Controls 3. Austin Energy’s Approach to Arc Flash Safety • Arc Flash Energy Assessment • Arc Flash TCC Curves • Energy, Time, & Distance 4. CSU Approach to Arc Flash Safety: • Arc Flash Energy Assessment • NESC tables / Software • Arc Flash TCC Curves • Conveyance of Hazard Information 5. What are You Doing?

2 NESC 2017 Changes

• Section 8, Part 4 – Work Rules for the Operation of Electric Supply and communication Lines and Equipment • Rule 410A3 was changed to include requirements to protect the head, face, hands, and feet of employees working on or near energized conductors, and now includes a recommendation for DC voltage.

3 NESC 2017 Changes

• 410A2: The employer shall provide training to all employees who work on or in the vicinity of exposed energized lines and parts. The training shall include applicable work rules required by this Part and other mandatory referenced standards or rules. (Typically OSHA)

4 NESC 2017 Changes • 410A3: The employee shall not wear an outer layer of clothing that could ignite and continue to burn when exposed to flames or the electric arc identified in the assessment. • 410A3b: Requires employees to cover the entire body with arc rated clothing and equipment having an effective arc rating not less than the anticipated level of arc energy, when the exposure level > 2 cal/cm².

5 NESC 2017 Changes

• Note 3: Multiple layers of arc rated clothing, (e.g., shirts pants, and jackets) have been shown by testing to block more heat than a single layer. (Removed the natural fiber undergarment part.) • Note 5: Engineering Controls can be utilized to reduce arc energy levels and work practices can be utilized to reduce exposure levels.

6 NESC 2017 Changes • 410A3 EXCEPTION 1: If the clothing require by this rule has the potential to create additional or greater hazards than the possible exposure to the heat energy of the electric arc, then clothing with an effective arc rating less than that required by this rule may be worn. • 410A3 EXCEPTION 2: Arc-rated equipment is not necessary for the employee’s hands when the employee is wearing rubber insulating gloves with protectors. Heavy-duty leather work gloves with a weight of at least 12 oz/yd may be worn if the estimated incident energy is not more that 14 cal/cm² • 410A3 EXCEPTION 3: Arc-rated equipment is not necessary for the employee’s feet when the employee is wearing heavy-duty work shoes or boots.

7 NESC 2017 Changes

• 410A3 EXCEPTION 4: Arc-rated equipment is not necessary for the employee’s head or face when the employee is wearing the appropriate hard hat - 29 CFR 1910.135 - and if the estimated incident energy is less than 5 cal/cm² (9 cal/cm² for exposures to single phase arcs in open air). • An 8 cal/cm² face shield may be used for exposures that are up to 4 cal/cm² greater than listed above.

8 NESC 2017 Changes

• 410A3 EXCEPTION 5: For DC systems with voltages 50V to 250V and 8000A maximum fault current, in lieu of performing an arc hazard analysis, clothing with a minimum effective arc rating of 5 cal/cm² shall be used.

9 Engineering Controls

• Remote Racking for Substation Breakers • Chicken Switch • Instantaneous Trip Relay / Maintenance Settings • Non-reclose setting • Arc Resistant switch gear • Increased Working Distance • Arc Flash Relay (light + over current = Trip) • NPARM such as Eaton ARMS (Arcflash Reduction Maintenance Systems) / VaultGard • Clip (Current Limiting Protectors) • Phase/Neutral Resistors and Reactors • Current Limiting Fuses, Superconductor fault current limiters • Other Ideas?

10 Instantaneous Trip Relay

An instantaneous Trip Relay (IT) is enabled whenever work is being done on a 600 amp, 12kV feeder in the breaker zone of protection. This will shorten the time the breaker will trip on a fault, reducing the arc flash energy. Network Protector Arc Reduction Module

Network Protector Arc Reduction Module (NPARM) works in a similar fashion as the IT relay. This makes the network protector act as a fast tripping circuit breaker, reducing the arc flash energy in the event of a fault. This is enabled only while work is being done in the vault. Remote Racking

A Remote Racker allows the substation breaker to be racked in or out from a remote location, typically outside of the breaker room. Remote Switching

The Chicken Switch® allows the substation breaker to be opened or closed from a remote location, typically outside of the breaker room. Hot Line Hold

A Hot Line Hold is where the recloser is set to non-reclose. Whenever work is performed in a recloser’s zone of protection, it should be set to non-reclose as part of the Hot Line Hold order. This will limit the recloser to one shot, reducing the arc flash energy. Current-Limiting Fuse Austin Energy’s Approach to Arc Flash Safety

17 AE Arc Flash Energy Assessment

2012 Findings Concern

Transmission/Subtransmission - 8-12 cal Limited

Substation Buses - 12kV/35kV/69kV/138kV/345kV - 8-16 cal Limited

Distribution Feeders - 12kV/35kV - Feeder Exits - 8-60 cal Significant

Distribution Transformers - Large 480V padmounts - 8-40 cal Significant

Networks - 277/480V Vaults - 80->200 cal Significant

Secondaries - 240V/120V - Large kVA - 8-20 cal Limited

Networks - 125/216V - 8 cal Limited

18 AE Baseline Arc Flash -“Default” 12kV settings

“Human Damage Curves” – Christopher Lee Brooks

“Default” Feeder Relay Settings Phase = 960A_TD=1 12 Cal Arc Flash for Ground = 360A _TD=5 “Default feeder relay” Fuse Curve of Largest Fuse (125 KS)

19 Arc Flash – Energy, Time, Distance Reduce Energy 30 MVA 9.5%Z power transformers for residential Current limiting fuses Reduce Time / Increase Distance Slugging transformers Short time instantaneous ARMS & VaultGard Maintenance settings OH & UG / all feeders in manhole Add equipment close time delays / remote switching Loop infrastructure & engineer bypasses were possible 20 Colorado Springs Utilities Approach to Arc Flash Safety

21 Arc Flash Energy Assessment Transmission & Distribution Generation Follows NESC tables & ArcPro Follows NEC: NFPA-70E & IEEE 1584

Need to know: Fault current, Protective device curve, working distance, arc gap, Phases, arc in box? 22 NESC tables

410-1 Clothing and Clothing Systems for Voltages 50 V to 1000 V AC – Developed from utility fault testing – 18 inch separation – Removed exception to use 4 cal/cm² 410-2 1.1 kV – 46 kV AC – 15 inch separation – Uses arc flash software 410-3 46.1 kV to 800 kV AC – Separation based on MAD – Uses arc flash software

23 Arc Flash TCC Curves

Calorie levels (somewhat) based on Table 410-2. 1.2, 4, 8, 20 cal/cm²

Based on fixed working distance, voltage, and gap

Open Air Single Phase only! 3 phase, in a box is 3 to 6 times higher

24 Arc Flash TCC Curves

•Compare Protective device clearing times – max. clear •Max. Fault current •Max. exposure time – 2 seconds

25 Conveyance of Hazard Information

Created a Safety Manual reference sheet covering all potential work areas, and includes: – Working distances used for the hazard calculations – Exception List for abnormal conditions – Clothing table with 4 Levels of PPE: 4, 8, 20, 40 cal/cm²

26 27 28 29 What are You Doing?

• Do you currently have an Arc Flash Safety Program? • How do you convey the arc flash hazard to employees? • What levels of PPE do you go with? • Do you require FR face shields for certain work areas? • Do you use any Engineering Controls to reduce the arc flash hazard and PPE requirements? 30