OFFICIAL PUBLICATION OF

FEBRUARY 5-7, 2019 NEW ORLEANS, LOUIS IANA

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YOUR POWER DELIVERY MEDIA SOURCE

10 FERC Tasks RTOs on Resiliency

22 Personalized DSM Services

25 Building Better Protection Schemes

These are the Drones… Improving T&D Asset Management

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SENIOR VICE PRESIDENT, NORTH AMERICAN POWER GENERATION GROUP

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EDITOR IN CHIEF Teresa Hansen

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DESIGNER II Heather Skeith

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POWERGRID International is the official publication of

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2 FROM THE EDITOR

4 NOTES

34 PRODUCTS

35 CALENDAR/AD INDEX

36 PARTING THOUGHTS

10 | REGIONALS TAKE LEAD ON RESILIENCY

BY ROD WALTON, SENIOR EDITOR

The Federal Energy Regulatory Commission’s (FERC’s) surprise unanimous decision last month rejected a

Trump Administration call to provide pricing support to traditional, storable generation sources. FERC

wants RTOs to tell it what’s best for grid resiliency.

16 | WINNING BY LOSING

BY GREG MYERS, SENSUS

Conservation voltage reduction (CVR) has emerged as an attractive solution for utilities seeking to gauge peak demand and optimize their power grid to help

control their energy costs while still delivering optimal power to customers.

19 | BECOMING A TRUSTED PARTNER BY ANDREW KLEIN, FIRSTFUEL SOFTWARE

As the energy industry evolves and utilities devise ways to offer more than just monthly bills to their

business customers, utilities are increasingly lending their expertise to help improve energy inefficiencies

like simultaneous heating and cooling.

22 | ENGAGING PROPOSITION TO PERSONALIZE DSM

BY KATE ROWLAND, ORACLE UTILITIES

More granular energy usage data from AMI has paved the way for more individualized program

modeling and demand side management (DSM) ser-vices. As a result, global spending on DSM is expect-

ed to increase between 2015 and 2024.

25 | BUILDING A BETTER PROTECTION SCHEME

BY STEVE WATT, JOANNA HOFER AND SHANKAR ACHANTA,

SCHWEITZER ENGINEERING LABORATORIES INC.

Even though recloser-aided precision fault clearing keeps the power on for customers in regions that are unaffected by the fault, a typical distribution

system can have areas that present challenges when faults occur.

29 | DISSOLVED GAS ANALYSIS BY PAUL J. GRIFFIN, DOBLE ENGINEERING CO., AND STEPHAN F.

BRAUER, MORGAN SCHAFFER LTD.

Dissolved gas analysis is one of the most power-ful tools asset managers have to determine the

health of their transformers. It is a cost-effective approach that can be used to detect problems

in the early stages and manage them as the condition evolves.

32 | BUILDING A BETTER WAY BY TUSHAR DAMLE, JONATHAN GOLDMAN, LUKAS GRABER AND

CHUNMENG XU, GEORGIA INSTITUTE OF TECHNOLOGY, AND MATTHEW

BOSWORTH AND MICHAEL STEURER, FLORIDA STATE UNIVERSITY

A team of students and researchers from two uni-versities are building a fast mechanical disconnect

switch, capable of opening in a few milliseconds or less while also carrying high continuous current

during normal operation.

UP, UP AND AWAY

BY ROD WALTON, SENIOR EDITOR

Drones are remaking the inspection and asset management landscape (and

airspace) for utilities. An old-timer might think that sounds like rubbish,

but that’s only the beginning.

13

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EDITOR IN CHIEF | TERESA HANSEN

DistribuTECH DOESN’T DISAPPOINT

Most of you probably already know that POWERGRID Inter-

national magazine is DistribuTECH’s official publication and its media partner. As such, I’m not only the magazine’s chief editor, but I’m also responsible for guiding DistribuTECH’s conference content and heading up its conference advisory committee. I have a lot of duties while at the event and I’ve often said the week of DistribuTECH is the hardest, but also the best, week of the year for me. Despite the busy schedule, long days and short nights, it’s exciting and rewarding to see the results of the arduous work put in by the PennWell team, as well as the many volunteer committee members. This year’s event didn’t disappoint. We had great atten-dance, packed conference sessions, a fabulous keynote and a busy exhibition hall. You’ll see a few short DistribuTECH pieces in the Notes section of this issue, but next month’s issue will include a DistribuTECH post show article, providing many details about the event and its hot topics.

I want to also mention, however, that as in year’s past, I mod-erated webcasts at the event. These webcasts are different than others we host throughout the year because they’re viewed not only by the online audience, but also by a live audience. The first webcast of the week occurred on Tuesday, Jan. 23, and featured a speaker from Excelsior Electric Membership Corp. (EEMC), headquartered in Metter, Georgia. Like many electricity provid-ers located near the east coast, EEMC was hit hard by Hurricane Irma and needed help from borrowed crews and contractors to restore service. In fact, because the company is still rebuilding,

the speaker could not travel to San Antonio, so he joined the webcast via Skype. He talked about a mobile app the compa-ny used to monitor the real-time GPS locations of over 150 workers, including the borrowed crews and contractors from six states, to complete restorations in 72 hours. It was fasci-nating to hear how a simple app, which could be downloaded on any Apple or Android device, played a significant role in restoration efforts.

The second webcast, which occurred on Wednesday, Jan. 24, was a panel discussion about utilities, cities and other entities working together to create smart communities. One of the pan-elists is an engineer with Avista Corp., who is working on Spo-kane’s (Washington) smart city initiative, Urbanova. Another is the energy and sustainability manager at the city of Charlotte, North Carolina. These two gentlemen revealed valuable infor-mation about their experiences and some of the challenges they’ve encountered working on these two smart city initiatives.

I’m not sharing this with you because it’s my duty to pro-mote webcasts, but because I learned a lot from both of these webcasts and want to make sure you know they’re available for you to view for free. You can find links to them on POWER-

GRID International’s website for the next six months. If either of these topics interest you, you’ll not be disappointed if you view the webcasts.

Most of DistribuTECH’s content focused one way or an-other on the electricity industry’s rapid transformation. This leads me to another major takeaway from DistribuTECH. Is the term “utility” outdated? Is it now a legacy term that should be replaced? I spoke to a few people about this during the show. We talked about how the business model of simply selling kilowatt hours is no longer sustainable, how most cus-tomers will one day be able to choose their electricity provider (of course, some already do), how customers expect better and more services from their electricity provider and how many companies outside the industry are anxious to meet those ex-pectations. The consensus was that utilities must find a way to connect with their customers, offer much more than just electrons and do a better job than the “outsiders” that are en-tering their space. Will this require a new label or name? We decided the answer is “maybe.” I expect future DistribuTECHs to provide clarity on that.

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NOTES

The end is near for a study by Salt River Project (SRP) and EPRI on the impact of electric vehicles (EVs) on the future grid.

The goal of the study, which will wrap up this year, is to determine what impact the increase in energy consump-tion will have on the grid as more chargers are installed in homes and businesses to meet demand.

FleetCarma data loggers were installed on the vehicles of 100 SRP customers who vol-unteered to participate in the study. The data loggers, which plug into the onboard diag-nostic port of vehicles, gather charging information such as time, duration and location.

“We wanted to see where and how EVs will impact our system,” said Kelly Barr, SRP’s senior director of environmen-tal management and chief sustainability and compliance executive. “We also wanted to learn how our customers with electric vehicles selected and utilized our pricing options to determine which price plan worked best for them.”

SRP decided to conduct its own study because Ari-zona drivers and climate are different than other parts of

CONTINUED ON PAGE 5

Pacific Gas & Electric (PG&E) will roll out a new electric time-of-use rate that it says will make energy use more efficient, minimize peak demand chal-lenges and give customers more rate options.

Starting in April, about 150,000 residential PG&E electric customers

will move into the new rate, although they have the option to choose another plan. The peak pricing will be from 4 p.m. to 9 p.m. every

day with the off-peak or lowest price in place during the other 19 hours.

“PG&E is committed to working together with our customers to ensure they understand how small shifts in when they use energy can make a big difference for the environment,” said Laurie Giammona, senior vice president and chief customer officer, in a statement. “We recognize that customers use energy differently and will provide information and tools to give customers greater control over how they use energy and help them choose the rate plan that best meets their needs.”

The time-of-use rate encourages a shift in us-age to times when demand is lower and renew-able resources such as solar are more plentiful, PG&E said. The utility will offer bill protection for the first 12 months to allow customers to try

the new rate plan risk-free.While customers who take no action

will transition into the new time-of-use plan in April, they will have the option of keeping their current plan or choosing an alternate rate plan.

The rate plan is part of a statewide ef-fort in which PG&E and other utilities are working with the California Public Utili-ties Commission (CPUC). Customers for the first phase were randomly selected

from across the service area to represent diversity in climate, household size and energy usage, among other factors.

PG&E plans for a full rollout of the new time-of-use rate plan starting either in late 2019 or late 2020, pending a decision by the CPUC.

California is committed to greater adoption of clean energy resources, but faces the challenges of the so-called “duck curve.” The duck curve illustrates how de-mand is low but renewables production high during an early part of a typical day when customers are away from home and then reverses in the evening. This creates the potential for over-generation early in the day and inadequate power in the evening.

PG&E Rolling out new Time-of-Use Rate in April SRP and EPRI Study EVs’ Impact on Grid

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the country. Drivers in SRP’s service territory tend to use their vehicle air conditioners more, which impacts the EV’s range.

Based on results of 100 participants, preliminary data found: • Roughly 4,400 current EV own-

ers in SRP’s territory use more than 9,121 MWh of energy a year, which equals the average energy consumption of about 652 homes.

• At SRP’s system peak at about 5 p.m., these vehicles also use more than 1 MW of electricity, which is equivalent to about 200 homes.

• Time-of-use (TOU) price plans were effective at incentivizing EV drivers to charge later than they normally would, which will help SRP meet customer de-mand without needing to add power plants.

• Current EV drivers are often re-ferred to as “early adopters,” and they tend to be more aware of the savings they can see by utilizing TOU plans and charging at cer-tain times of the day. SRP hopes to educate future EV owners on the benefits and encourage them to use TOU programs and avoid charging during peak times.

The study began in June 2016 and is expected to end this year. SRP will con-duct a second study later this year with some of the newer EVs that have a bat-tery range of more than 200 miles, such as the Chevy Bolt and Tesla Model 3.

CAISO. “We will now seek to provide re-liability coordinator services to our own system, as well as to other interested parties in the Western Interconnection.”

A reliability coordinator is responsi-ble for complying with North American Electric Reliability Corp. (NERC) and regional standards, including providing oversight, monitoring operational and security risks, acting or directing action to preserve system reliability and provid-ing leadership in system restoration fol-lowing a major reliability event.

The reliability coordinator services the CAISO is contemplating will include outage coordination and day-ahead planning, in addition to real-time mon-itoring for reliability.

CAISO is extending its withdrawal period from the required 18 months to 20 months to ensure seamless coordination with Peak

Reliability’s members on the transition. During that time, the ISO will work through an open and transparent process with all interested stakeholders to complete neces-sary tariff changes, oversight functions and certification processes from NERC and the Western Electricity Coordinating Council (WECC) in a timely manner.

The ISO plans for its new reliability coordinator unit to be certified and op-erational by spring 2019.

The California Independent System Operator (CAISO) announced plans to become its own reliability coordinator and offer these services to other balanc-ing authorities and transmission opera-tors in the western United States.

CAISO has given notice of its withdraw-al to its current reliability coordinator, Peak Reliability, and to each of its funding members, effective September 2019.

Reliability is an essential element of operating the electric grid, and CAISO has supported a single reliability coor-dinator in the Western Interconnection to provide the most comprehensive and coordinated view of the system.

The likely departure of the Mountain West Transmission Group (MWTG) from Peak and resulting increased costs to all participants, and Peak’s partnership with PJM to offer market services, caused CAISO

to believe it is now necessary to pursue its own withdrawal. The ISO, therefore, will provide these services for its own foot-print as soon as possible, and to other parties across the West, at reduced costs.

“The ISO reluctantly takes these steps and will collaborate with the rest of the funding parties to ensure continuity of reliability services and to avoid any party being adversely affected financially,” said Steve Berberich, president and CEO of

CONTINUED FROM PAGE 4

CAISO Unveils Plan to Take Grid Reliability Reins of its System

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Dominion Energy is buying troubled South Carolina holding utility SCANA in a deal estimated at almost $15 billion, the com-panies announced in January.

The deal, if completed, also promises close to $3 billion in payments or write-off benefits for those South Carolina utility customers served by SCANA’s subsidiary.

SCANA, through its South Carolina Electric & Gas (SCE&G) unit, has held a huge stake in the failed work to build two new nuclear reactors at the V.C. Summer Station. The utility and its partner, state-owned Santee Cooper, abandoned work on Units 2 and 3 this summer after years of delays, billions in cost overruns and con-tractor Westinghouse’s bankruptcy filing.

A Dominion spokesman said that the merged company will not restart develop-ment of the Summer nuclear station.

Dominion’s offer includes about $7.9 billion stock and, including debt, totals about $14.6 billion. The all-stock merger, if completed, would result in an immediate, average cash payment of $1,000 to SCE&G

customers within 90 days of closing, ac-cording to the release.

News reports have indicated that the cus-tomer payments could total about $1.3 billion.

“We believe this merger will provide sig-nificant benefits to SCE&G’s customers, SCANA’s shareholders and the communi-ties SCANA serves,” Dominion CEO Thom-as Farrell said in a statement. “It would lock in significant and immediate savings for SCE&G customers—including what we believe is the largest utility customer cash refund in history—and guarantee a rapidly declining impact from the V.C. Summer project.”

The deal also promises a write-off of $1.7 billion in V.C. Summer’s 2 and 3 capital and regulatory assets. This means that amount will not be collected from customers and speeds up the overall customer-cost time-line to 20 years instead of previously pro-posed 50 to 60 years.

Dominion’s offer also vows to com-plete the $180 million purchase of natu-ral-gas fired Columbia Energy Center at

no cost to customers.“Dominion Energy is a strong, well-re-

garded company in the utility industry and its commitment to customers and communities aligns well with our values,” said Jimmy Addison, CEO of SCANA, in the announcement. “Joining with Domin-ion Energy strengthens our company and provides resources that will enable us to once again focus on our core operations and best serve our customers.”

SCANA shareholders will receive 0.6690 shares of Dominion Energy common stock for each SCANA share, according to the re-lease. The combined company will provide electric and natural gas to more than 6.5 million customers in eight states, making it one of the largest utility holding compa-nies in the U.S.

If approved by regulators, the merger would be completed by 2019.

Dominion Buying SCANA After Nuclear Project End

BY ROD WALTON, SENIOR EDITOR

EnSync Inc., doing business as EnSync Energy Systems, a developer of distributed energy resources (DERs), announced the sale of a 20-year power purchase agreement (PPA) for a 792-kW solar project for a resi-dential community in Hawaii. It did not dis-close the buyer. The project will serve over 200 individual meters—with the flexibility to add more meters—and is grid-tied. It will export unused energy to the grid un-der the Customer Grid-Supply (CGS) tariff.

Using its proprietary modeling technol-ogy, EnSync Energy performed significant technical and financial analyses to optimize project sizing and setup for delivering the least expensive and most reliable electricity. EnSync Energy modeled, for example, how unit vacancy interacts with residential load volatility and concluded that a grid-tied

project design could protect the value generated by the solar project. The result-ing design, execution and successful PPA balanced load needs, special permitting re-quirements and CGS utility arrangements to maximize savings were considered.

EnSync Energy said in a release that its modular technology approach also enables the residential complex to easily scale capacity in the future.

“The many complexities of creating a PPA for this large residential develop-ment project, with so many units and in-dividual load and production profiles, are indicators of the challenges our solutions address and the value we bring to the res-idential marketplace,” said Brad Hansen, CEO and president of EnSync Energy in the release. “Our capability to perform

increasingly intricate analysis and mod-eling, in addition to applying expertise in policy implications, enables us to con-struct a customized PPA that benefits all stakeholders economically.”

This site is one of more than 22 con-tracted commercial projects in Hawaii, which will account for more than $33.4 million in electricity sales over the terms of the agreements.

Construction will commence in the coming months, according to the release.

EnSync Energy Sells PPA for 790 kW Solar Project in Hawaii

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NOTES

Schneider Electric announced major collaborations on the mi-crogrid front during DistribuTECH 2018, including a $4.5 million municipal project in Connecticut and a partnership with a new energy-as-a-service company backed by a $500 million capital commitment from the Carlyle Group.

The financial world is seeing the potential in be-hind-the-meter energy solutions worldwide and wants in, Mark Feasel, vice president of Schneider Electric’s smart grid and microgrid segment, said during a briefing during DistribuTECH week.

“There are more bankers walking around here at DistribuTECH than any year in the past,” he said.

The most immediate news announced by the Boston-based firm was a $4.5 million microgrid project with the city of Milford, Connecticut. It will team gas-fired combined heat and power generation with energy storage and could be solar-ready for future additions.

The microgrid will power five critical facili-ties in Milford, including a senior center, mid-dle school, city hall, government center and apartments for the elderly. Construction has begun and should be completed by the first quarter of 2019, Feasel noted.

City leaders were concerned after see-ing what happened with Irma and vot-ed to approve a project that will provide protection against grid outages, he said. The project is funded partially by a grant from the Connecticut Department of En-ergy and Environmental Protection, with Milford funding the generator and battery energy storage system. Schneider provides the design, electrical equipment and grid management expertise.

“More and more, we’re seeing the negative impacts of 500-year storms on entire regions,” Feasel said. “The unprecedent-ed nature of these storms is causing municipalities to come to grips with the need to offer resilient power and a shelter and microgrids that operate independently in the event of a grid outage. . . The microgrid will offer Milford residents peace of mind.”

Many of Schneider’s previous microgrid projects combined solar power with storage and a backup generator. Milford chose the gas-fired option because of its low-cost and lower emissions profile.

“It’s greener than what they have today,” Feasel noted. The generator will need to run 24 hours a day. He also pointed

out that about 40 percent of microgrids have a gas-fired generation

component, about the same percentage as solar.The company’s microgrid profile took a potentially even bigger

leap by detailing its partnership with Dynamic Energy Networks. The startup, which is a portfolio company of investment giant Carlyle, looks to jump up into the microgrid space soon, buying and operating assets with power sold back to the customer on long-term deals.

A graphic delivered during the presentation indicated that the U.S. microgrid market is expected to exceed 3.7 GW by 2020. Dy-namic Energy Networks is set up to move soon on various proj-ects, using Schneider as a technical partner well-versed in micro-grid installation and control technologies.

“We see this as a fast-growth path and it needs a lot of capital,” said Karen Morgan, a longtime renewables executive who is CEO

of Dynamic Energy Networks. “We feel we can get into the market quickly.”

The company certainly will consider existing projects to acquire, she added. However, Schneider’s front-line engage-ment with microgrid construction can move that into fledg-ling projects.

Taking the operational financial burden off of municipal, com-mercial and industrial customers is a key driver for future transac-tions, Morgan pointed out. The business plan of buying the power at long-term predictable costs should be more attractive to top leaders who want cleaner energy and resiliency against outages, Morgan predicted.

“This is a C-suite solution,” she said. “Schneider has been in this a long time and is a leader. I think we’re hitting a tipping point.”

Schneider Details Milford Microgrid, Partnership with Carlyle-Financed Startup

BY ROD WALTON, SENIOR EDITOR

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The march to develop industry-agreed standards for distribut-ed energy resource management systems (DERMS) took a major leap forward on Jan. 22, as utilities and vendors connected in the effort and offered thoughts on the best path ahead.

The Smart Electric Power Alliance (SEPA) hosted its annual Grid Management Working Group focused on DERMS require-ments, drawing nearly 150 participants to discuss the needs for standards which address dangers like cybersecurity, load curves and reserve power flow as well as potential functions such as ag-gregation and voltage control. The working group met at the Hen-ry G. Gonzalez Convention Center, site of DistribuTECH 2018, which occurred Jan. 23-25.

“The group was formed to do something that was not done very well in the past,” said Vibhu Kaushik, director of grid moderniza-tion efforts at Southern California Edison (SCE), one of the utilities driving the push for DERMS standards that can then be adopted by vendors. Kaushik pointed out that SCE is facing 5,000 rooftop solar applications per month in its service territory and might see electric vehicle adoption rise 25-fold to meet clean emission goals over the next two decades.

SEPA got the ball rolling two years ago at DistribuTECH 2016. Since then, distributed energy resources (DER) have proliferated as solar panel costs fell, but industry standards struggled to keep pace.

The “DERMS Terms” movement, as some call it, is working to change that.

“The whole objective for SEPA is driving multiple stakehold-ers’ collaboration to set the direction and provide clarity around

DERMS,” said Sharon Allan, chief innovation officer for SEPA. “That clarity reduces risk for everybody” from ratepayers to util-ities and vendors.

SEPA has released a DERMS requirements document for com-ment among industry participants. Utilities will benefit by being able to acquire systems that are more likely to provide standard-ized capabilities—such as inverters—while vendors are guided in their own product development efforts.

Mike Ratliff, chief technical officer with Enbala, said that clarity is key. The phrase DERMS creates some confusion industry wide because some think it’s all about coordinating solar panels and reserve power while others think it’s about smoothing out the load curve or is a new version of demand response.

“I think about new power systems,” Ratliff said of DERMS’ capa-bilities. A new-level DERMS control would remove the dangers of managing high solar photovoltaic penetration, he added.

Pacific Gas & Electric (PG&E) also has learned lessons on ways to manage DER spread out across the grid, said Sameer Kalra, who helps oversee that utility’s technology strategy and innova-tion efforts.

“We’re looking at near-term non-wires alternatives projects,” Kalra said. “The whole planning is changing in a key way. DERMS is still not available off the shelf.”

That could change soon if the continued Grid Management Working Group efforts prove fruitful. SEPA hopes to produce a more detail document in the next year with the goal of seeing standardized DERMS products showing up the marketplace by 2020 or soon thereafter.

SEPA, Collaborators Tackle DERMS Standards at DistribuTECH

BY ROD WALTON, SENIOR EDITOR

Innovative projects from across the U.S., including one devel-oped by a non-utility, won the 2018 POWERGRID International

and DistribuTECH Projects of the Year awards on Jan. 23, Dis-tribuTECH 2018’s opening day. Winners were revealed during the keynote address at the Henry B. Gonzalez Conference Center in San Antonio.

The editors of POWERGRID International —the official publi-cation of the DistribuTECH Conference & Exhibition—selected one wining project in each of four categories: Distributed Energy Resource Integration, Grid Optimization, Demand Response/En-ergy Efficiency, and Customer Engagement.

Teresa Hansen, Editor in Chief of POWERGRID International and conference chairwoman for DistribuTECH, said this year’s awards reflect the changing nature of smart grid dynamics.

“The grid is becoming ever more technically complicated and diffused with things like sensoring, AMI data analysis and dis-tributed energy resources,” Hansen said. “This year’s winners

prove that the next era of the smart grid is now. It’s becoming less controlled in the traditional way, as proven by the fact we have a non-utility winner for the first time in memory.”

The winner for Distributed Energy Resource Integration was Blue Lake Rancheria, a tribal reservation in northern California, chosen for its microgrid project that operates within the Pacific Gas & Electric service territory. Public Service Electric & Gas won the Grid Optimization Project of the Year for its Energy Strong Advanced Technologies D-SCADA Program. The winner for De-mand Response/Energy Efficiency Project of the Year is Kansas City Power & Light’s Residential and Small Business Demand Re-sponse program. The Customer Engagement Project of the Year is Sacramento Municipal Utility District’s Distribution Operations Transformation.

A more detailed article about the 2018 POWERGRID Interna-

tional and DistribuTECH Projects of the Year will be featured in the March issue.

POWERGRID International Names Project of the Year Award Winners

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NOTES

NOTESEYEON THEWORLD

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I b e r -

drola has

connec t ed

its Wikinger off-

shore wind farm to

the German power grid. The facility was

built over the last 18 months in the Baltic

Sea.

By reaching this milestone, Wikinger

adds 350 MW capacity to the system and

will supply renewable energy to 350,000

homes, representing more than 20 per-

cent of the power used by the state of

Mecklenburg-West Pomerania, in whose

waters the project is located.

Wikinger, Iberdrola’s first solo offshore

project, had a particularly complex con-

struction phase. In its major stages:

• 280 piles were driven into the sea bed

to hold the foundations

• The offshore substation jacket was installed

• The Andalucía offshore substation was

installed and commissioned

Iberdrola Connects Wind Farm to German Power Grid

• The underwater cables connecting

with Lubmin onshore substation were

installed and commissioned in coordi-

nation with 50Hertz, a German system

operator

• More than 80 kilometers (50 miles) of

underwater array cables were run and

commissioned

• The 70 jackets and wind turbines were

installed and commissioned

Iberdrola has an operations, control

and maintenance center in the port of

Sassnitz.

With an investment of nearly €1.4 bil-

lion ($1.7 billion), Wikinger will prevent

almost 600,000 tons of CO2 from being

released into the atmosphere each year,

according to the company.

One of the key infrastructures at

Wikinger is the offshore substation,

named Andalusia, which will be used

jointly by Iberdrola and 50Hertz. It

was manufactured by Navantia at

its Puerto Real (Spain) facilities and

weighs 8,500 tons—more that the

Eiffel tower and the Statue of Liberty

combined. It is the wind farm’s ener-

gy core.

The Chinese power transmission com-

ponent market is set to exceed $30 billion

by 2024, according to the latest study

by Global Market Insights Inc. Favor-

able regulatory reforms pertaining to the

integration of a sustainable electric net-

work along with ongoing expansion of

cross-border interconnections will posi-

tively influence the industry growth, ac-

cording to a Global Newswire release.

Stringent energy efficiency protocol

along with advancing smart monitoring

and control technologies will fuel the

power transmission component market

growth, the release reads. Perpetual aux-

iliary capacity addition with an aim to in-

tegrate a sustainable energy mix coupled

with enhancing distributed generation

technologies will further complement the

business outlook. In addition, ongoing

expansion of high tension direct current

electrical networks along with positive

outlook toward energy efficiency to curb

Transmission Component Market Expanding, GMI Report Shows

the accumulating losses will foster busi-

ness growth.

High-voltage projects at or above 765

kV will grow because of rapid industrial-

ization coupled with ongoing expansion of

high tension networks to curb overall ag-

gregate technical and commercial losses,

according to the report. Extension of utility

aided grid networks along with favorable

regulatory inclinations toward cross border

transmission interconnection will drive the

power transmission component market.

Global inclination to sustain energy

conservation coupled with supportive

measures to ensure security of supply will

thrust the power transmission component

market size. Expansion of smart-grid net-

works along with supportive policy inter-

ventions will further accelerate the indus-

try growth. In 2017, Sweden, Germany,

France, U.K., Germany and Italy proposed

investments of more than $130 billion with

an aim to enhance smart grid adoption

across the nations in compliance to the

smart grid agreement.

The South Africa power transmission

component market is anticipated to grow

due to the increasing demand for reliable

and continuous electricity along with rapid

micro-grid expansion.

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GRID RESILIENCY

Grid Resiliency Timeline

April 14, 2017: Energy Secretary Rick

Perry releases memo detailing his

concerns about the erosion of baseload

power generation through coal and

nuclear retirements. He calls for a study

on the issue.

August 24, 2017: Department of Energy

delivers on Perry’s promised study,

which blames the reduction of baseload

generation coal and nuclear on the rise of

natural gas and renewables.

September 29, 2017: Department of

Energy sends a notice of proposed

rulemaking (NOPR) to the Federal

Energy Regulatory Commission (FERC),

seeking cost-of-service price supports

for baseload generation sources that can

store 90 days of supply on-site.

December 2017: FERC asks for more

time to study the Department of Energy

proposal beyond the allotted 60 days.

Early January 2018: The northeast U.S.

grid essentially withstands a major winter

storm, forebodingly nicknamed a “bomb

cyclone,” proving to many observers that

grid resiliency is strong.

January 8, 2018: FERC rejects the

Department of Energy request, but

asks regional transmission and system

operators to come back with their

evaluations of grid resiliency.

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GRID RESILIENCY

Federal energy regulators have put their trust in re-gional grid operators—and not the government—to find the best way forward on resiliency issues amidst a renewable power revolution.

The Federal Energy Regulatory Commission’s (FERC’s) surprise unanimous decision last month rejected a Trump Administration call to provide pricing support to traditional, storable genera-tion sources. The move was surprising because four of the five FERC commissioners were Trump appointees.

Those storable generation sources, of course, were primarily nuclear and coal. Both could have benefitted from the subsidized boost. Coal was a centerpiece of the president’s promises for an indus-try revival after eight years of Obama environmen-tal edicts, while nuclear has long been maligned for huge costs and risk-reward debates despite its ze-ro-emission power potential.

Nonetheless, the grid resiliency focus of U.S. re-gional transmission organizations and independent system operators (RTOs/ISOs) intensified after FERC put the ball in their courts to come up with suggestions in about 60 days after the early January decision. Those organizations include California ISO (CAISO), Southwest Power Pool, Electric Reli-ability Council of Texas, PJM Interconnection, Mid-continent ISO (MISO) New York ISO and ISO-New England (NE).

“We are encouraged by efforts underway by PJM and ISO-NE to better understand vulnerabilities in their systems, and support similar efforts in other regions where analyses of potential resiliency issues could be helpful,” the FERC order read. “We also are encouraged by the ongoing work in MISO to devel-op a long-term plan to address changing system needs in light of an evolving resource mix.”

Regulators placed more faith in the grid overseers

Regionals Take Lead on Resiliency

FERC Chooses RTOs/ISOs Over Proposed Fed Support for Coal, NuclearBy Rod Walton, Senior Editor

than in the judgement of En-ergy Secretary Rick Perry, whose department proposed the subsidies. On Sept. 29, 2017, Perry’s Department of Energy (DOE) sent the pro-posed rulemaking to FERC which had only recently reached a quorum with four Trump appointees.

Perry got the ball rolling with an April 14, 2017, memo, which expressed his concern that an “erosion of baseload power is compromising a reli-able and resilient grid.” A later DOE report also worried that the rise of variable renewable energy hastened the retire-ment of baseload generators, which is probably true to some degree. Some propo-nents have noted, however, that the move to renewables is based more on changing economics. Solar is getting cheaper and more competi-tive against traditional power sources.

The DOE’s notice of pro-posed rulemaking (NOPR) arrived on FERC’s desk some five months after Perry’s let-ter. It argued that grid resil-iency was best achieved by generation sources that can hold up to 90 days storage on-site. Those sources need a

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GRID RESILIENCY

little financial help to stay robust, so the argument went. “Distorted price signals in the commission-approved orga-

nized markets have resulted in under-valuation of grid reliabil-ity and resiliency benefits provided by traditional baseload re-sources, such as coal and nuclear,” Perry wrote in a September letter to FERC announcing the proposed rule. “The rule will ensure that each eligible reliability and resiliency resource will recover its fully allocated costs and thereby continue to pro-vide the energy security on which our nation relies.”

FERC took its time mulling over the pro-posal, but then as a whole disputed that coal and nuclear merited cost-of-service rate payments beyond free-market prices. The commission’s lone remaining Obama appointee, Cheryl LaFleur, countered in her January 8 post-ruling statement that such “out of market” price supports went against the free-market grain. The current distribution generation reformation was not unlike other industrial transforma-tions which helped some and hurt others, she noted.

“As with all transitions, there have been market winners and losers,” Lafleur wrote. “Resource turnover is a natural conse-quence of markets, and the reduced prices that result from greater competition are a benefit to customers, not a problem to solve, unless reliability is compromised.”

Not to be outdone by an Obama appointee, two Trump-cho-sen FERC commissioners also argued the free-market case and pointed out that the previous DOE study, despite its concerns over coal retirements and intermittent solar and wind genera-tion, produced no evidence of reduced grid reliability.

“To the contrary, the addition of a diverse array of genera-tion resources, including natural gas, solar, wind and geother-mal, as well as maturing technologies such as energy storage, distributed generation and demand response, have in many respects contributed to the resilience of the bulk power sys-tem,” Commissioner Richard Glick countered in his statement attached to the FERC order.

He went on to offer a sympathetic tribute to coal workers hurt most by the nation’s shift toward cleaner emitting resources and cheaper natural gas. The same considerations extended to nuclear workers, Glick added.

“We have a history in this country of helping those who, through no fault of their own, have been adversely affected by technological and market change,” Glick wrote. “But that is the responsibility of Congress and the state legislatures. It is not a role that the Fed-eral Power Act provides to the commission.”

Commissioner Neil Chatterjee, another Trump appointee,

acknowledged the “staggering” change of pace in grid generation, noting that nearly 16,000 MW of natural gas and a combined 20,000 MW of combined wind and solar photovoltaic capacity were brought on-line just in the two years ending in 2015. Meanwhile, close to 42,000 MW of coal and nuclear were being retired in close to the same period.

Nonetheless, market-based mecha-nisms are better ways to ensure just and reasonable rates, he wrote.

“I share this preference for market-based solutions and would have urged RTOs/ISOs to identify market mechanisms to address these concerns,” Chatterjee added.

Ultimately those most impacted by the grid resiliency de-cision had their say. Energy Storage Association CEO Kelly Speakes-Backman said she was encouraged by FERC’s deci-sion to let grid operators take the lead.

“By building a robust record of fact from the system oper-ating bodies responsible for reliability and resilience, and by taking the important first step of defining both, FERC is rightly assuring that any actions taken will be holistic and effective,” Speakes-Backman said.

PJM Interconnection—the RTO that oversees transmis-sion activities for millions of customers from Illinois to Dela-ware—pointed out it was already on the job. “We will continue to work on both issues and look forward to working with the commission and stakeholders on these important issues going forward.”

Entergy—the southern U.S. utility holding company that owns and operates a generation mix including nuclear, gas, coal and hydro—agreed that requiring more information from RTOs/ISOs was the appropriate move.

Ultimately, the future of policy on grid resiliency will likely derive from what the RTOs/ISOs tell federal regulators. They are on the front lines of the grid.

FERC did not find anything unjust or unreasonable about current RTO/ISO tariffs, but it does want deeper answers on how they will keep the grid humming despite the proverbial and actual storms and clouds that arise in the future. In ad-dition, the commission seemed encouraged and relieved that entities such as MISO and PJM were already doing the work through ongoing resiliency studies.

“At the heart of each of these initiatives is collaboration between RTOs/ISOs and their stakeholders,” the FERC order read, “and we look forward to receiving stakeholder input on the submissions. The topic of the new proceeding—resilience of the bulk power system—will remain a priority of the com-mission and we expect to review the additional material and promptly decide whether additional commission action on this issue is warranted.” | PGI

Lafleur

Glick

Chatterjee

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DRONES

Up, Up and AwayDrone Value Grows With Transmission Expansion and Digital Revolution

By Rod Walton, Senior Editor

Drones are remaking the inspection and asset management landscape (and airspace) for utilities. An old-timer might think that sounds like rubbish. That’s only the beginning.

A recent report by consulting firm PwC high-lighted an example of a flame-throwing drone clearing trash from power lines as among the in-novative uses of unmanned aerial systems (UAS) by utilities. PwC estimates that drone services may be worth about $9.5 billion annually to the global power and utilities sector, mostly by help-ing spot potential outage dangers before they happen and cutting down penalties paid for grid downtime. They also apparently can keep the grid from getting grubby.

Duke Energy is now considering shifting its drone uses from pure research and development approaches to part of the daily framework, while it’s already committed to developing a trained workforce focused on that particular tool. North Carolina-based Duke is not alone in finding new ways to create value out of drones. They and oth-er industry players already know drones are up, up and here to stay. The key is going next level with it.

“I believe with increasing focus on items like data security, owners of critical infrastructure will continue to move away from lower priced ‘hobby’ UAS and invest in more sophisticated platforms that satisfy a myriad of internal requirements which, of course, come at a higher price point,” said Jacob Velky, manager of UAS, aviation ser-vices, at Duke Energy.

Trash clearing, line-mile observation and cre-ating 3-D models are completely unique but equally crucial tasks well-suited to drones, pro-ponents say. What comes next is lifting off into engineering workflows as part of daily planning.

Drone operator readies UAV for takeoff.

Photo courtesy of Duke Energy

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DRONES

PHIL CHRISTENSEN HARJEET JOHAL JACOB VELKY

Both flight paths seem to have value. Phil Christensen, senior vice president of real-ity modeling and cloud services for Bent-ley Systems, has seen how drones cou-pled with reality modeling have improved efficiency on several grid-related projects worldwide.

“I think every utility is going to be us-ing UAVs (unmanned aerial vehicles),” Christensen said. “The question is which assets and functions should they focus on first, based on which will deliver the best payback. One question to ask is: When will having a detailed 3-D model and a high-resolution photoset either let me do something I couldn’t do before—like mea-sure assets from off-site in the office—or allow a 20 percent or more reduction in time or cost for a function on a particular asset?”

Global power transmission networks could rise more than 10 percent to over 4 million circuit miles, according to PwC. The rising demand for renewable energy such as solar and wind, which is more abundant and affordable in areas distant from more populated load centers, will push necessity for more long-distance transmission lines and put a greater bur-den on utilities and reliability coordina-tors to maintain those systems once built.

Every year, the transmission sector loses about $169 billion due to network failures and forced shutdowns, accord-ing to PwC’s report. Drones are touted as helping cut up to 50 percent in inspection costs via reduced manpower expenses and higher detailed 3-D modeling.

“The savings vary, of course, but the biggest one is avoiding the need to go

back to a site or an asset to gather addi-tional information,” Bentley’s Christensen pointed out. “Certainly, manned inspec-tions will continue. For example, flying UAVs over live substations is not permit-ted by some utilities. But having the reali-ty model of the asset, created from a prior UAV flyover, can be a big help in making manned inspections more effective.”

Reality modeling—what a concept. Bentley Systems has its ContextCapture service involved in numerous tower, wind farm and other infrastructure projects in China, Australia, South Africa, Italy and the U.S. At the Macheng Caijiazhai Wind Farm project in Hubei Province, China, for example, low mountain ridges and steep slopes posed challenges for site location and access road-building. The project developers, Hubei Electric Power Survey and Design Institute, used reality modeling insights to resolve location and routes. Bentley indicates that combined 3-D and reality modeling helped save money and cut 20 days off the construc-tion period.

Washington D.C.-based company Measure offers drone-as-a-service for utilities that don’t want to spend on owning such assets. It has performed inspections on transmission infrastruc-ture from 46 kV to 500 kV. Utilities need to make decisions based on what level of commitment they want and the size of the project, said Harjeet Johal, Measure’s vice president of energy. Either way, drone inspections offer a higher level of detail such as “missing pins, rust, dam-aged in insulators,” he noted.

All is not blue sky with drone adoption,

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DRONES

Johal cautioned. Virtual cockpit competency—or a lack there-of—is unforgettable.

“With drone operations, lack of skilled and knowledgeable pi-lots tends to be the biggest challenge,” he said. “Pilots must be licensed by the FAA and have a good understanding of drone regulations. With power line inspections, we are flying near crit-ical infrastructure and we must ensure that electro-magnetic in-terference from high voltage equipment does not impact drone operation.”

Pilots who don’t understand magnetic fields around ener-gized equipment can cause tremendous problems if an accident occurs, he pointed out. Proper training and experience are nec-essary. Most of Measure’s pilots are former military or civilian pi-lots with commercial licenses. For those utilities that choose to operate their own drone programs, in-depth training is a must.

Duke’s Velky is well aware that drone technology is an emerg-ing industry and vulnerable to notable gaps in experience for those users who don’t pursue upper-level pilots. He believes all entities using drones should develop high standards regardless of whether it is an in-house or third-party service.

“Sitting within our manned flight department, I am remind-ed by our manned pilots of one of the key differences between when they fly and when we fly: Our feet are on the ground, theirs are not,” Velky said. “Poor decisions made by the UAS pilot or RPIC (remote pilot in command) typically allow the RPIC to go home that evening, even if the UAS is lost. Operating the UAS in the same airspace as manned aviation is a task that should be taken seriously every time the UAS is pulled out of the case for a mission.”

Utilities like the New York Power Authority and vendors such as GE have talked about development of “digital twins.” These virtual copies of something real—whether it’s a substation or a power plant—may allow operators to use data in previously in-conceivable ways to test a product. This could ramp up efficien-cies and avoid wrong turns if the modeling is accurate enough.

It’s not a complete reality yet (virtually or otherwise) but some tech-savvy folks believe we can get there from here. The most direct route, they say, is by air.

“I think creating a full inventory of digital assets to mirror the physical assets in the grid can be achieved through increased drone usage,” Bentley’s Christensen said. “This capability will provide a dramatically improved understanding for all utility team members in what they have in the field and its condition.”

But remember, we’re not there yet.“A much higher level of drone usage will be needed, not just to

create this library of digital twins of physical assets but also to keep it up to date as the grid evolves,” Christensen added.

The grid evolution is not slowing down. Measure’s Johal echoed the sentiment that regulators need to keep up. Regula-tors have not only the power to require strict safety standards but also ease up the barriers to the mechanical birdies in the sky as well as the renewable power-generating, transmission and distribution assets fixed to the ground.

“Today, drones are used primarily for storm response and spot checks,” Johal said. “Increasing the level of automation, easing regulations and systematically using drones for larger-scale in-spections would create additional efficiencies for utilities’ main-tenance operations.”

Drone flight to inspect substation.

Photo courtesy of Pacific Gas & Electric

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CONSERVATION VOLTAGE REDUCTION

Winning by LosingConservation Voltage Reduction Helps Utilities Survive PeaksBy Greg Myers, Sensus

All electric utilities have a need to better gauge demand during peak load times. Too high and ev-erybody pays more. Too low and you risk brown-outs and blackouts.

Conservation voltage reduction (CVR) has emerged as an attractive solution for utilities seeking to gauge peak demand and optimize their power grid to help control their energy costs while still delivering optimal power to customers.

Following is an overview of how CVR can help utilities optimize delivery and make better use of their energy resources, including a case study featur-ing a utility that leveraged available infrastructure to implement a CVR program and reaped significant benefits as a result.

VOLTAGE LEVELS REFRESHER

Nominal voltage for a residential home in the U.S. is 120 volts (V) with an acceptable variation of +/- 5 percent (+/- 6 V). A range between 114-126 V, therefore is generally con-sidered “good” power supply, though many utilities regularly operate around 120 V to stay on the safe side of good supply.

Distribution feeders are supplied from elec-tric substations. Voltage regulation is managed through regulators located in the substations or on the feeders. Impedance settings in the regulator controllers help correct the adjusted voltage on the feeder. This approach typically results in higher voltages at the beginning of the feeder and lower ones along the feeder as voltage drop occurs along the distribution lines.

Long feeders can be challenging because volt-age can drop below 114 V at some point. When

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CONSERVATION VOLTAGE REDUCTION

this condition occurs, utilities use field equipment (capacitor banks, line regulator banks) to adjust the voltage back to “good” levels. From this adjust-ed point, the voltage will again drop along the feeder’s lines.

HOW CVR CAN HELP

CVR gives electric utilities the ability to view voltage data and make adjustments in real time for more accuracy and control. By leveraging CVR, therefore, electric utilities can reduce their system demand during peak events.

With the right CVR solution in place, utilities can: • Monitor and manage

real-time voltage data us-ing metrology, communica-tions and analytics

• Measure and optimize voltage across the entire distribution network, from substations to homes and businesses

• Ensure the proper level of service voltage is delivered to customers

• Reduce overall energy us-age for the utility system through right-size voltage

• Save money with less need for in-house generation (larg-er utilities) or for purchased power (smaller utilities)

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CONSERVATION VOLTAGE REDUCTION

BEGINNING THE CVR JOURNEY: WHERE TO START

The keys to getting the most value from CVR are gathering the right data to make informed decisions on how to best manage and deliv-er power during peak events, and having the right network to trans-mit this data for effective, real-time analysis. In many cases, this infrastructure might already be in place, especially for utilities that have deployed an advanced metering infrastructure (AMI) solution for consumption data transmission and analysis.

With the right AMI technology, utilities can use meters to col-lect and transmit usage data at regular intervals, then analyze this data to understand demand in real time and make the proper adjustments. For data transmission, many utilities and munic-ipalities have implemented private networks that offer two-way communication over a licensed spectrum that uses a star net-work design. This type of network can offer point-to-multipoint connectivity for faster data transmission without the bandwidth issues that often plague public mesh networks.

AMI can be instrumental in enabling CVR, creating a system that uses voltage data from electricity meters working together as a feed-back loop of actual values. The voltage information is measured in two ways:

1. The meters on the feeder can be programmed to send voltage data into head end software as part of their normal billing read.

2. Some meters have the added capability of calculating a one-min-ute average of voltage, and frequently reporting those detailed values. These act as bellwether meters, which are typically 1 to 2 percent of the electricity meters spread out over the distribution system.

The combined approach provides additional voltage resolution for improved accuracy. Utilities use the voltage data to identify which feeders are running with lower or higher voltage and can then adjust them as needed. The data may also indicate which feeders are the best candidates for further CVR load reduction.

Finally, utilities can use advanced analytics software applica-tions to receive CVR information from meters installed on the net-work, which they can then use to determine where voltage is too high or too low. These applications can also help indicate where to use a SCADA system to adjust levels by raising or lowering voltage to get it back to “good” levels.

WAKE EMC: USING CVR TO

ACHIEVE BOTTOM-LINE IMPACT

When Don Bowman, Wake EMC’s manager of engineering, and his team deployed an AMI solution—comprised of more than 43,000 meters and an advanced two-way communication network—in 2012, CVR wasn’t one of the driving factors. They soon discovered, however, that it offered some of AMI’s greatest benefits.

“We started to see a change in energy rates, which caused us to look at ways to reduce peak loads,” said Bowman. “Rather than asking our customers to make changes, we decided to look inter-nally at ways we could clean up our side of the system, and CVR was one of the solutions we identified.”

With a system for reading and transmitting voltage data in real

time already in place, Wake EMC quickly jumped on opportunities to reduce peak loads without impacting customers’ power supply.

“We had this massive amount of data coming into our system, and what we learned is that there were enough inefficiencies that we could correct to make a substantial impact on our costs,” said Bowman.

Though they typically run loads between 120 V and 125 V, Bowman and his team learned they could reduce loads to 114 V during peak events while still supplying adequate power to cus-tomers. By using built-in alarms in their AMI solution, the system could alert them to when voltage was in danger of running below safe levels.

“Having real-time voltage alarms in your meters is key for CVR to make sure you’re not bringing it down too low,” reiterated Bowman. “In the time we’ve been doing CVR with our AMI solu-tion, I haven’t had one residential customer call me to complain about low voltage.”

In more than three years since beginning their journey with CVR, Wake EMC has seen costs savings that have stretched be-yond what Bowman initially thought possible.

“For every half of a percent of load we reduce we’re saving up to $100,000 per year, and we’ve managed to reduce it by up to 4 percent in some cases,” said Bowman. “On average, we save some-where between 2 and 3 percent, up to $600,000 annually. We’re in-credibly proud of the system we’ve implemented.”

CONCLUSION

CVR is an effective solution that provides strong economic bene-fits while meeting critical utility and customer needs.

With CVR, many utilities, like Wake Electric, have experienced significant voltage reduction as well as a drop in energy consump-tion. Specific amounts depend on the load types on a particular feeder, but it is common to see corresponding energy savings of 1 to 2.5 percent on feeders running CVR.

To recap, utilities that use CVR can: •Reduce system peak demand consumption •Improve service quality •Boost efficiency •Extend the life of equipment •Lower operating costs •Enable preventive maintenance •Offer voltage visibility and insights across the network •Provide information to ensure adequate power generation •Balance energy supply and demandTaken together, the energy saved during peak events across the

system can add up to significant cost savings for the utility that can be reinvested in further improvements or passed on to the customer. | PGI

Greg Myers is vice president of global electric marketing at

Sensus. Greg has 25 years’ experience in the electric industry,

including eight years of service at Sensus. He received a

bachelor’s of science degree in electrical engineering from

West Virginia University of Technology and earned a Master of

Business Administration from John Hopkins University.

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ENERGY EFFICIENCY

Becoming a Trusted Partner

Utilities can use Customer Data to Help Business Customers Improve Energy Inefficiencies

It’s the heart of heating season and many smaller buildings have switched off their cooling equipment until the warm weather returns. For larger buildings with high internal loads from computers and people, however, cooling systems often continue to operate right alongside heating systems. The need for both heating and cooling is even more prevalent in the fall and spring when temperatures can range from 45 F to 75 F. When managed improperly, inefficient energy use can occur.

Simultaneous heating and cooling (SHC) occurs when heating and cooling systems battle it out to condition the same space at the same time. Sometimes SHC is used on purpose for humidity control—for example, to defog car windows. More often, howev-er, SHC happens unintentionally and wastefully. In these cases, it’s like driving your car with the accelerator fully depressed while using the brake to control your speed. Unnecessary SHC can per-sist because resulting space temperatures are often comfortable, therefore, tenants don’t notice or complain to building manage-ment staff. This allows SHC to fly under the radar.

What businesses might not know is that their utility can be a trusted partner that understands their energy use and might be able to provide invaluable cost-saving advice. As the energy in-dustry evolves and utilities devise ways to offer more than just monthly bills to their business customers, utilities are increasingly lending their expertise to help improve energy inefficiencies like SHC. By leveraging streams of historic customer data, utilities can provide customized recommendations based on the specific needs and known preferences of each customer.

Utilities can provide businesses with insights that indicate if

and when there is an efficiency issue. In the case of heating and cooling, utilities can do this by analyzing:• Previous monthly energy usage. For example, SHC might be

an issue if building occupancy has been the same all year and energy consumption is higher in the spring and fall.

• Heating and cooling operations. By offering incentives for a building “check-up,” including a manual inspection of heating and cooling operations, utilities can determine if systems are op-erating at the same time in the same building zones.

• HVAC system performance. Utilities should analyze us-age data and perform a physical evaluation for more complex HVAC systems to ensure everything is up to snuff, and identify any needs for repairs or replacement.

An office building in Connecticut that has electric heat and air conditioning is a good example. The building’s electric consump-tion would be expected to be lowest in the relatively mild days of the shoulder seasons, when both heating and cooling needs are minimal. Instead, Figure 1 shows that during most of the shoulder season days (the blue line), energy consumption is higher than in summer or winter days.

Assuming the building occupancy was the same all year, it’s possible that SHC drove this high shoulder season consumption. A utility, therefore, could recommend investigating to determine whether this was an issue for this building. When unnecessary SHC is suspected, utilities might recommend several measures to help mitigate the problem: • Adjust heating system settings. The customer could disable

By Andrew Klein, FirstFuel Software

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ENERGY EFFICIENCY

heating systems that serve the perime-ter areas anytime the outdoor tempera-ture is above 60 F during occupied days, and 50 F at night. This will help reduce the instances of heating and cooling sys-tems operating at the same time.

• Look for portable space heater use.

The customer could check whether ten-ants are using portable electric space heaters, particularly in areas that are overcooled by central systems.

• Evaluate equipment operating schedules. The utility can help the customer assess operating schedules for existing build-ing zones. This is the first step in elim-inating running the HVAC when floors or areas are unoccupied. In addition, by implementing an overtime occupancy system, ventilation can be provided in areas that need to be occupied on an occasional basis.

• Correct thermostat settings. The customer should ensure heating and cooling setpoints are spread by at least 4 F, and check that the night setback is operational. If thermostats that con-trol perimeter heat are independent of those controlling central air handling units, they should have setpoints that are several degrees lower than that of the air handling unit thermostat.

• Link air handler discharge tempera-

ture to outdoor air temperature. Instead of resetting air handler discharge temperature based on return air tempera-ture, the control air handler discharge temperature should be based on outdoor air temperature. Controlling discharge temperature based on return air can drive the discharge temperature lower when there is excessive space heating.

For comparison, Figure 2 shows sea-sonal days for an electrically-heated office building in Maryland. The shoulder season (again shown in blue) exhibits a morning double peak pattern similar to the winter (shown in green). There is, however, less reason to suspect unnecessary SHC be-cause shoulder electric consumption nev-er exceeds that of the other seasons.

Although there is no evidence that the

Maryland building is operating with un-necessary SHC, the graph provides addi-tional insights into the building’s winter performance. During late evening and early morning (6 p.m. to 6 a.m.), the winter consumption is higher than the shoulder and summer—an indication that electric heat is operating during the unoccupied parts of the day. Furthermore, the winter consumption, which is likely associated with heating, begins to increase at about 3 a.m. This is earlier than necessary for most buildings, and particularly for buildings that experience Mid-Atlantic winters.

This building’s energy consumption can be lowered by making changes to the building management system. If the heat-ing system is over-operating at night, the following measures are recommended:• Choose the right nighttime tempera-

ture. Proper night setback should be im-plemented across all zones of the build-ing. An unoccupied heating setpoint of 55 F is recommended.

• Look for other unoccupied setbacks.

If heat is operating at night, it might also be operating during the daytime on weekends and holidays. Make sure

FIGURE 1 : SEASONAL ELECTRICITY CONSUMPTION WITH EVIDENCE OF SHC

FIGURE 2 : SEASONAL ELECTRICITY CONSUMPTION WITH NO EVIDENCE

OF SIMULTANEOUS HEATING AND COOLING

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unoccupied setpoints apply to all unoccupied periods of the year.

• Check zone thermostats. Often, operators find that many building areas have had their independent zone thermostats changed, causing spaces to overheat.

• Tighten HVAC equipment schedules. The existing building schedules should be modified to properly mimic the occupan-cy schedule of the building. For office buildings, HVAC equip-ment should start between 6 a.m. and 7 a.m. and shut-down between 5 p.m. and 6 p.m. The heat can be turned down and the building can “coast” the last hour of the day.

Another tool for measuring building performance is the weath-er response chart. The building’s electric meter data and local

weather data can be fed into an analytical weather model that isolates the weather-related energy use each hour of the year. The average weather-related electric demand (kW) is plotted for each corresponding outdoor air temperature. Figure 3 illustrates the weather response for the Maryland building.

The first thing that can be confirmed from the weather re-sponse is the heating and cooling type. Because the weather-re-lated consumption increases as weather goes from mild to hot, the building is air conditioned, and because the weather-related consumption increases as weather changes from mild to cold, the building is heated with electricity.

Further, the occupied weather response (red) is plotted sepa-rately from the unoccupied weather response (blue), illustrating the effectiveness of nighttime HVAC setback. Ideally, if the build-ing completely shuts down at night, the blue line would be flat, meaning there is no change in consumption due to weather at night. It is clear from Figure 3 that the building is not setting back HVAC equipment at night.

By providing these types of proactive and personalized recom-mendations, curated and prioritized above the hundreds of other possible opportunities in a building, utilities develop deeper rela-tionships with customers. Through valuable interactions, utilities can spur a positive dialogue about the appropriate energy services for their business customers. In addition, with software-based an-alytics, utilities can perform the analysis and make many of the needed recommendations to thousands of their customers in-stantly, no longer constrained by account managers’ time or areas of expertise. Utilities that take steps to proactively engage with business customers in this way will secure their spot in the value chain of the ever-evolving energy landscape.

Ecova collaborated with Zpryme on a report and surveyed

more than 1,000 business customers—500 with 20 or fewer em-

ployees (small business) and 500 with more than 20 employees

(medium to large business). Sixty percent of small business re-

spondents look first to their local utility for advice on efficiency

efforts, according to the survey.

In addition, more than three-fourths (77 percent) of medium to

large businesses replied that energy efficiency and management

were high priorities within their organizations, while 51 percent of

small businesses said the same thing.

Some key findings were:

• Business customers are already interested in energy efficiency.

Small to medium businesses are already interested in energy

efficiency work, with 73 percent of surveyed small businesses saying

they do or have plans to implement energy efficiency projects.

• Utility-business customer relationships need strengthening.

Small to medium businesses look first to their local utility for en-

ergy management advice, but just 26 percent of those surveyed feel

their utility is addressing the energy challenges they face very well.

• Budget is a barrier for most small business customers. While

large businesses cite many barriers to participation in energy

efficiency work, most small businesses cite budget as their

primary obstacle.

• Small businesses value utility-provided energy usage data.

Ninety percent of small businesses value utility-provided energy

usage data and recommendations created from analytics.

Find more business customer market insight in the whitepaper

“The Utility Business Customer Survey on Energy Management:

Piecing Together the Puzzle on Small, Medium and Large Cus-

tomer Perspectives” produced by Ecova and Zpryme and avail-

able on Ecova’s website.

Survey Reveals Business Customers Want Utilities’ EE Advice

FIGURE 3 : WEATHER RESPONSE CHART

Andrew Klein is a building energy engineer at FirstFuel Software,

a SaaS company that provides a business customer engagement

platform for utilities. Through the analysis of building energy

use, Andrew arms utilities with recommendations on energy

efficiency measures for their business customers. Andrew is also

a Registered Professional Engineer in Massachusetts and holds a

Certified Energy Manager credential.

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METER DATA MANAGEMENT

Long gone are the days of the one-way utility experience in which util-ity-customer moments were limited to bill payment and power outages. With nearly 62.4 million residential ad-vanced metering infrastructure (AMI) installations in the United States alone by the end of 2016 (per the U.S. Energy Information Administration), the smart meter has heralded a mas-sive change in the utility-customer relationship.

Over the past decade, the most success-ful AMI rollouts have put customers front and center. By translating smart meter data into helpful insights and programs, utilities have won regulatory approval, ramped up digital engagement, unlocked

Engaging PropositionUtilizing Meter Data for Better

Demand Side ManagementBy Kate Rowland, Oracle Utilities

new value streams and dramatically increased customer satisfaction.Better, more granular energy usage data from AMI has paved the way for more

individualized customer program modeling and more personal demand side management (DSM) services, all designed to provide customers with better en-ergy savings results. As a result, global spending on behavioral and analytical

DSM is expected to increase roughly tenfold between 2015 and 2024, rising from $214.7 million to $2.5 billion, according to Navigant Research’s “Behavioral and Analytical Demand-Side Management” study.

In the past, the primary goal for most utility demand side management (DSM) programs was to help

cost-effectively defer the need for the addition of new electricity generation to the system.

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METER DATA MANAGEMENT

USING BIG DATA TO ENRICH

CUSTOMER EXPERIENCE

In the past, the primary goal for most utility DSM programs was to help cost-ef-fectively defer the need for the addition of new electricity generation to the system. As the industry changes and customer ex-pectations of their utilities continue to rise, however, utilities have begun to use DSM programs to meet those expectations, pro-vide value-added services and enrich the customer experience. This all begins with meter data.

When smart meters were first intro-duced, one of the touted future benefits was to be able to provide customers with a near real-time view of their energy usage and empower them to better manage their electricity budget. In the ensuing decade,

customer as an individual with specific needs and interests.

EDUCATING TO ENGAGE

There are a number of tools utilities can use to deliver customer insights, from home energy reports and utility web portals providing usage information and energy efficiency tips to proactive high-bill alerts and even peak manage-ment alerts.

Just as data analytics is used across the utility enterprise to provide new insights and intelligence, it is also used to then embed intelligence within the enterprise to create new value. The same is true for the utility customer. Once customers are aware of the ways in which they can ben-efit from the data from their smart me-ters, the utility can begin to demonstrate those benefits in tangible ways by sharing energy efficiency insights using proactive alerts, including weekly energy updates via e-mail to help customers track their energy habits in a more granular fashion, and high bill alerts to help them curb their usage in a more immediate fashion, rather than after the bill hits.

Once a customer becomes interested and engaged in saving energy, he or she is more likely to want to engage with the util-ity online, whether it be to regularly track energy usage, pay a bill or look for new ideas and ways in which to save energy. For customers participating in time-of-use pricing programs, online engagement can be particularly appealing to track usage from day to day.

An engaged customer—one who now looks at his utility as a trusted energy advisor—is also more likely to partic-ipate in peak management programs, whether those be behavioral demand re-sponse-related or rebate-related. In addi-tion, most importantly, a more engaged customer—one with the ability to bet-ter manage his or her relationship with the utility, and use of that utility’s prod-ucts—is a more satisfied customer.

Kate Rowland is a writer and industry strategist for

Oracle Utilities. She has more than two

decades’ experience in the energy and

utilities industry.

meter data has proven to be one of the most effective tools utilities

have for engaging and empow-ering customers in the long

term.Behavioral DSM focuses

on customer education as the lever to encourage energy savings. By inte-grating AMI data with demographic data (age, gender, income, etc.), be-havioral data and psycho-graphic factors, utilities

can create highly person-alized experiences for cus-

tomers, from proactive high bill alerts to insightful energy

savings advice. It’s all about the content and the timing: delivering

the right insights at the right moments to maximize their effectiveness.

While electricity usage data on its own is useful—even before smart meters, en-ergy-savvy customers were comparing month-against-month usage from printed monthly bills—the real value of more gran-ular AMI data is in the new insights that can be derived from analyzing it alongside other relevant data to make recommen-dations that are pertinent not to the cus-tomer base as a whole, but rather to each individual customer, mirroring their own experiences and preferences.

Data analytics provides a way to better categorize customers based on their ener-gy habits, and then use that information to generate the insights and promote the pro-grams that are most relevant to them. In essence, data analytics provides the ability to create a “segment of one,” treating each

Controlling energy use has come a long way since the days of

analog thermostats, like the one pictured here.

Customers of progressive utilities that provide usage date can now use smart phones

and other internet-enabled devices to monitor and control their energy usage.

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SYSTEM PROTECTIONSYSTEM PROTECTION

Building a Better Protection Scheme Protection-Class Fault Indicators Improve Response, System Visibility and Equipment Life

Eighty percent of power distribution overhead faults are momentary. These

momentary faults are often detected and cleared by reclosers that are posi-

tioned along distribution lines. Reclosers divide the distribution lines into sec-

tions, and they open or close these line sections independently of the main

line, clearing faults without disrupting service to a whole line or an entire

distribution system. Even though this recloser-aided precision fault clearing

keeps the power on for customers

in regions that are unaffected by the

fault, a typical distribution system

can have areas that present challeng-

es when faults occur. A new genera-

tion of specialized sensors, however,

are helping advance protection to a

new level.

ALTERNATIVE STRATEGIES

FOR SINGLE-MINDED

PROTECTION SCHEMES

Because most faults clear them-

selves, reclosers minimize the impact

of faults by interrupting the fault cur-

rent, allowing momentary faults to clear. This allows breakers at the substation or along

the distribution lines to automatically restore power to the line after a momentary fault.

While this method is effective, distribution protection engineers continue to face

fault-clearing challenges. One reason for this is that each recloser control is typically

programmed to operate according to one protection scheme. For line sections that in-

clude both underground and overhead lines or those that have fuse-protected laterals

with varying ranges of criticality and accessibility, employing a single protection scheme

is not always ideal.

For example, some areas of the same section might require delays for fuse blowing

By Steve Watt, Joanna Hofer and Shankar Achanta, Schweitzer Engineering Laboratories Inc.

A protection-class fault indicator system

optimizes recloser control operation to reduce

outages or momentary faults.

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SYSTEM PROTECTION

(trip saving) while other areas would benefit from fast-er tripping ( fuse saving). Applying a single scheme to these varied sections results in missed opportunities to optimize power system metrics, such as System Av-erage Interruption Duration Index (SAIDI), Momen-tary Average Interruption Frequency Index (MAIFI) and Customer Average Interruption Duration Index (CAIDI). These metrics provide insights that help operators reduce future outages to better serve their customers.

PROTECTION-CLASS FAULT INDICATOR

SYSTEMS OPTIMIZE LINE PROTECTION

A new, economical protection approach is to improve the performance of the reclosers already on a system. Distribution protection engineers can do this by in-stalling a protection-class fault indicator system. This new type of fault indicator system sends fault detec-tion signals to the recloser control or relay so that protection devices make better decisions. Because the system quickly communicates that there is a fault—typically within 6 milliseconds of a fault occurrence—the recloser control or relay has the information it needs to apply the best protection scheme for the situ-ation while the fault is active on the line.

Utilities applied faulted circuit indicators (FCIs) for decades to locate faults, but the idea of using them to improve protection is new. To enhance protection, the FCI system must provide information to recloser con-trols and feeder relays faster by several orders of mag-nitude. These high-speed sensor systems are optimal for the following medium-voltage applications:• Hybrid fuse-saving and fuse-blowing protection

schemes that use the same recloser or relay• Precise protection selectivity at underground-to-over-

heard transitions• Coordination delay bypassing to accelerate protection

and reduce the duration of damaging fault current

Protection-class fault indicator systems consist of fault transmitters and receivers. Fault transmitters contain a current transformer and clamp onto an overhead feeder line. Fault transmitters harvest ener-gy from the line to which they’re attached, allowing them to operate without batteries. When a preset

trip threshold is exceeded, the radio in the fault trans-mitter sends high-speed wireless signals to the fault receiver. Each transmitter also sends a periodic radio link status to the receiver to indicate that the transmit-ter is operational.

In a protection-class fault indicator system, the fault receivers can simultaneously receive fault informa-tion from multiple fault transmitters, which greatly improves the wireless communications performance because each transmitter can communicate without delay. The receiver communicates to a protective relay using a high-speed protocol.

The protective relay or recloser control uses the fault information from the transmitter and receiver system to optimize protection schemes during a fault. If radio communications from the transmitters are lost, the relay or recloser control continues to operate with standard protection schemes.

MIXED PROTECTION SCHEMES

For a given distribution feeder segment, a protec-tion-class fault indicator system optimizes recloser control operation to reduce outages (SAIDI) or mo-mentary faults (MAIFI). Adding a transmitter and receiver system to a recloser control or relay allows

distribution protection engineers to mix protection schemes and create hybrid schemes that balance SAIDI and MAIFI metrics.

Example 1:

Fuse Blowing as Primary and Fuse Saving as Secondary

Fuse-blowing schemes are commonly used in ur-ban areas where feeders have numerous taps. In this scheme, a fault on a tap causes a fuse at the beginning of the tap to blow. The outage is confined to the tap, and the recloser control prevents reclosing attempts on the main line, which improves MAIFI metrics. The downside of this approach is that temporary faults can cause a fuse to blow and create a permanent out-age for the tap, impacting SAIDI metrics. To optimize both SAIDI and MAIFI metrics, distribution protec-tion engineers can employ a hybrid fuse-blowing and fuse-saving scheme that uses the protection class fault indication system. They can apply fault transmitter sensors on taps where fuse saving is preferable. These

Eighty percent of power distribution overhead faults are momentary.

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SYSTEM PROTECTION

taps might have a critical load or experience frequent momentary

faults. When the relay or recloser identifies faults on these taps,

protection can be instantly switched to fuse saving, tripping be-

fore the fuse blows.

Example 2:

Fuse Saving as Primary and Fuse Blowing as Secondary

When fuse saving is the primary protection scheme, maximum

effort is spent to clear all temporary faults on the feeder. This ap-

proach is commonly used in rural areas, large coverage territories,

rugged terrain, areas with severe weather, and when personnel

availability is constrained. The goal is to take only outages for

permanent faults. Fuse saving improves SAIDI metrics and op-

erations and maintenance costs. The downside of this scheme is

that repeated reclosing results in poor MAIFI metrics. In a hybrid

scheme, distribution protection engineers can use fault trans-

mitter sensors on taps where fuse blowing is preferable. These

might be taps with low, noncritical loads or locations where it is

easy for service technicians to replace fuses. When the relay or re-

closer identifies faults on those taps, protection can be instantly

switched to fuse blowing.

PROTECTION AT UNDERGROUND-TO-OVERHEAD

FEEDER TRANSITIONS

Feeders with underground-to-overhead transitions present utili-

ties with a protection challenge. Underground faults are usually

permanent, while overhead faults are usually momentary. Util-

ities are often unwilling to reclose on faults near an under-

ground-to-overhead transition because they do not want to re-

close on underground faults, which most likely are permanent.

Reclosing on permanent faults stresses the infrastructure and

equipment and can damage cables and connectors. Therefore,

knowing the precise location of a fault is critical to choosing the

best protection scheme.

A protection-class fault indicator system enables fine-tuned

protection at feeder underground-to-overhead transitions. Dis-

tribution protection engineers can place fault transmitters at the

overhead-to-underground transition points. If a fault transmitter

detects a fault, it sends a message to the receiver that is connect-

ed to the feeder relay. The relay can then change its protection

scheme. This fine-tuned selectivity approach reduces outages and

improves SAIDI metrics.

BYPASS COORDINATION DELAYS

To clear faults from lines and apparatus along a distribution cir-

cuit, engineers preset a sequence of operations in overcurrent pro-

tection devices by specifying certain time-current characteristic

curves and settings. This is known as coordination.

There is coordination between protective devices installed in

a series configuration and also between protective devices and

fuses. A protection-class fault indicator system provides a reclos-

er or relay with the necessary information to reduce unnecessary

Improved fault location information allows personnel to reduce patrol times and drive directly to the faulted tap or segment, improving CAIDI metrics.

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SYSTEM PROTECTION

coordination delays. For example, operators can use the system

to determine when a fault is upstream from the next recloser, on

unfused taps, or on unfused main line segments. The system can

then trip faster in these cases.

FASTER PROTECTION

Reducing the duration of faults not only improves reliability

metrics but also has the following benefits:

• Extended equipment life: Clearing faults before they can fully

develop reduces stress on infrastructure

• Improved system stability. Short fault-clearing times reduce

voltage fluctuations and sags

• Increased safety. Extended fault durations can lead to an in-

creased chance of fire damage or electrocution

During fault conditions, voltages can fluctuate. Phases adjacent

to the faulted phase can experience voltage sags. Shortening the

duration of faults lessens the impact of voltage deviations, which

is especially important for devices, such as consumer electronics,

that have tight tolerances for power quality.

Conductors that encounter trees or other equipment during

faults can create showers of sparks. The longer the fault stays on

the line, the longer the shower of sparks continues, potentially

starting catastrophic fires. Broken or fallen conductors also can be

an electrocution hazard. Isolating faults faster reduces the chanc-

es of fires and other safety hazards.

The recloser control can retrieve the fault-detection informa-

tion from the protection-class fault indicator system and send it

back to a SCADA or outage management system. This provides

line crews with more specific location and phase information for a

fault, reducing patrol time.

Improved fault location information allows personnel to reduce

patrol times and drive directly to the faulted tap or segment, im-

proving CAIDI metrics. The ability to identify the faulted segment

ahead of time is especially helpful when feeder lines are numer-

ous, difficult to get to and far from major roads or when crews face

poor weather conditions.

PROTECTION-CLASS FAULT INDICATOR SYSTEMS

CAN IMPROVE RECLOSER OPERATIONS

Reclosers are valuable additions to any distribution system be-

cause they improve system reliability, but their operations can

be greatly enhanced with sensors that can detect faults and

transmit valuable location information quickly to a recloser

control or relay. Adding protection-class fault indicator systems

creates opportunities to optimize protection schemes in relays

or recloser controls.

Distribution systems benefit when protection-class fault indi-

cator systems are combined with advanced recloser controls and

feeder relays. The key benefits include:

• Improved SAIDI, CAIDI and MAIFI metrics from mixing

fuse-saving and fuse-blowing schemes

• More precise protection for underground-to-overhead transi-

tions, which reduces permanent outages and the risk of reclos-

ing on underground faults

• Faster protection on radial feeders by eliminating unnecessary

wait times for coordination

• Increased equipment life

• Improved system stability and power quality

• Improved safety

• Reduced patrol time for fault location

Advanced recloser controls and feeder relays have helped im-

prove reliability metrics because they use more precise fault-de-

tection methods, clear a greater number of temporary faults and

enable effective fault isolation and restoration schemes. By adding

protection-class fault indicator systems to existing protection sys-

tems, utilities can further improve reliability, realize additional dis-

tribution system benefits and optimize their power system. | PGI

Steve Watt is the senior program manager for communication

products at Schweitzer Engineering Laboratories Inc. (SEL).

He worked in the information technology industry for over

20 years at Hewlett Packard before joining SEL in 2012. He

received his bachelor’s degree in mechanical engineering

from Virginia Polytechnic Institute and State University.

Joanna Hofer is a technical writer at SEL and has been with

the company since 2008. She holds a bachelor’s degree from

the University of Texas at Austin and a master’s degree from

Portland State University.

Shankar Achanta is engineering director for the precise

time, fault indicators and sensors division at SEL. He joined

the company 2002 as a hardware engineer, developing

electronics for communications devices, data acquisition

circuits and switch-mode power supplies. Shankar currently

holds nine SEL patents, and he is an inventor on several

patents that are pending in the field of precise timing and

wireless communications. He received his master’s degree in

electrical engineering from Arizona State University in 2002.

A protection-class fault indicator system enables fine-tuned protection at feeder underground-to-overhead transitions.

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TRANSFORMER HEALTH

Dissolved gas analysis (DGA) is one of the most powerful tools asset managers have to determine the health of their trans-formers. It is a cost-effective approach that can be used to detect problems in the early stages and manage them as the condition evolves. The amount and rel-ative composition of gases detected can be used to categorize developing prob-lems. Categories of problems include: overheating of paper (cellulosic materi-als), overheating of the dielectric liquid (mineral oil or other), partial discharge activity or arcing. With this information, the data can be analyzed to determine the severity of a fault condition by exam-ining changes in the relative composition and rate of generation of dissolved gases. A test program with more frequent DGA samples, on-line DGA monitors and oth-er tests can be used to further elucidate the nature of the condition and the neces-sary urgency of response. The results can be used to manage risks and decide if an asset should remain online. In some cas-es, consideration might be given to con-trolling operating conditions, such as load and operating temperature to limit the risk of an in-service failure, which could have wider impacts with greater costs. The results might serve to avoid a costly unplanned outage.

MANAGING TRANSFORMER PROBLEMS

As an asset manager, it is useful to sort transformers into two main categories. For most, available data should indicate

Dissolved Gas Analysis

A Key Tool for Transformer Asset Health ManagementBy Paul J. Griffin, Doble Engineering Co., and Stephan F. Brauer, Morgan Schaffer Ltd.

that the transformer is oper-ating normally and aging at an expected rate without de-veloping faults. Transformers in this category can be tested at established routine test in-tervals based on voltage class, power class and importance to the power system. The other category would be transform-ers exhibiting problems such as accelerated aging or devel-opment of fault conditions. For these units, more frequent DGA samples, or on-line mon-itoring can be applied. Addi-tional test methods might also be used to refine the condition

FIGURE 1: FAULT DETECTION USING A

HYDROGEN AND MOISTURE DGA MONITOR

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TRANSFORMER HEALTH

assessment. For example, if the DGA indicates partial discharge (PD) activity, then electrical PD tests can be performed. If PD is confirmed, acoustic sensors can be applied to the transformer walls to locate the fault(s).

Depending on the nature of the gassing, other on-line tests such as infrared thermography can provide useful comple-mentary information, as can off-line tests such as power factor and capacitance, leakage reactance, winding resis-tance, exciting current, sweep frequency response analysis and winding turns ratio. These tests can be used by the asset manager to determine the probable cause of the gassing and the appropriate urgency of response.

WHEN TO APPLY DISSOLVED GAS ANALYSIS

One challenge in applying DGA methods is that gases can some-times be generated when no transformer fault is present. The generation of abnormal amounts of gases under normal oper-ating temperatures is known as “stray gassing,” which can vary with different oils and other dielectric liquids. There are test methods including ASTM D 7150 to help distinguish stray gas-sing from fault gassing.

For expensive transformers, those in critical applications, or units with possible problems, on-line DGA monitor-ing is recommended. These monitors provide a wealth of

information, updated every few hours or less, so changes in the gassing pattern or rates can be tracked and any sudden changes automatically reported. DGA monitors allow the informed management of critical transformers while they

remain in operation. They have proven useful in preventing unplanned outages and avoiding costly transformer damage as fault conditions begin to deteriorate.

As an example, Figure 1 (previous page) shows how an on-line DGA monitor can reveal intermittent fault activity that would be difficult to detect using annual laboratory DGA testing alone. This transformer is located at a hydroelectric generation station in a tropical location. Following many

years of service, the transformer insulation had absorbed a high level of moisture, resulting in water-in-oil content aver-aging from 45 to 55 parts per million (ppm), which is shown in blue in the lower panel. Short periods of high load resulted in increased heating, which drove moisture out of the cellu-lose insulation, rapidly increasing water content in the oil. Following these events, most of the additional moisture was slowly re-absorbed by the cellulose over several days. During these short periods of high-water content in oil, large increas-es in dissolved hydrogen (H

2) were also recorded (top panel

in green), with a sudden onset and a slow decline. These H2

Depending on the nature of the gassing, other on-line tests such as infrared thermography can provide useful complementary information, as can off-line tests

such as power factor and capacitance, leakage reactance, winding resistance, exciting current, sweep frequency response analysis and winding turns ratio.

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TRANSFORMER HEALTH

spikes might have indicated short-lived thermal fault behavior, or par-tial discharge activity. To investigate, a more complete DGA analysis was performed with a portable DGA analyzer. Methane (CH

4) was pres-

ent at 46 ppm and ethane (C2H

6) was present at 59 ppm, but no ethylene

(C2H

4) or acetylene (C

2H

2) were detected. As the high concentration of

hydrogen was relatively short lived, another possible source of hydro-gen formation seemed likely, specifically the electrolysis of free water condensing in the valve. If the hydrogen was being formed in the main tank and mixing in the bulk oil, the concentration would not decay so rapidly. If moisture was condensing in the valve area, electrolysis of free water could result in hydrogen formation, which would cease when the free water was dissolved. A multi-gas DGA monitor could have been in-

stalled to study how other gases evolved during these transients. If the issue was thermal, then methane and ethane would be generated at the same time as the hydrogen. On the other hand, if the issue was electrolysis of free water, only hydrogen and oxygen would be formed. The on-line monitoring indicated this transformer’s reliability would be improved by drying the insulation system.

As another example, Figure 2 shows data recorded by a multi-gas DGA monitor during the first days of service of a new 900 megavolt ampere (MVA) transformer in the southern U.S. After installation on site, the unit was filled with new, degassed mineral oil. Within a few hours of being energized, the transformer began to exhibit significant fault gassing. The monitor readings rose steadily over 24 hours, includ-ing an increase in acetylene (C

2H

2) from 0 to 6 ppm, and the transform-

er was de-energized later that day after which the gas levels quickly stabilized. Laboratory DGA samples confirmed the concentrations re-ported by the monitor. The gassing behavior indicated a “T3” thermal fault with temperature exceeding 700 C, which could have quickly es-calated to a catastrophic failure. The comparatively-constant CO read-ings suggest the cellulose insulation was not directly involved. The transformer was returned to the manufacturer for root cause analysis and repair under warranty.

Paul J. Griffin is the vice president of professional services at Doble Engineering. He leads Doble’s consulting, testing and laboratory services groups. Griffin has been with Doble since 1979 and has published over 50 technical papers pertaining to testing of electrical insulating materials and electric apparatus diagnostics. He is a Fellow of ASTM and a member of Committee D-27 on Electrical Insulating Liquids and Gases. Mr. Griffin is a member of the IEEE Insulating Fluids Subcommittee of the Transformer Committee.

Stephan Brauer has managed product development and technology strategy at Morgan Schaffer since 2005. Brauer previously led technology development at small, medium and large organizations in both the private and public sector, specializing in precision measurement instruments. He holds a degree in engineering physics from Queen’s University and a Ph.D. in experimental physics from McGill. Brauer is the author of numerous publications and is a member of IEEE, APS, ASTM and CIGRÉ.

FIGURE 2: MULTI-GAS DGA MONITORING OF A DEFECTIVE

NEW TRANSFORMER

DISSOLVED GAS ANALYSIS:

A POWERFUL ASSET MANAGEMENT TOOL

Because DGA methods are sensitive to such a wide variety of problems that may arise inside power trans-formers, they now play a central role in many asset management programs. The primary categories of faults that may be identified using DGA methods in-clude thermal faults affecting oil, overheating of paper (cellulosic materials), partial discharges and arcing. Recent DGA diagnostic tools are also able to identify various subtypes of these faults including carboniza-tion of paper and nonhazardous stray gassing that may occur when new oils are put into service (per M. Duval, DGA Challenges at ASTM, IEEE, CIGRÉ, presented at IEEE Power and Energy Society meeting in Dallas on May 2, 2016). These methods are also in-creasingly capable of diagnosing faults in transformers filled with insulating fluids other than mineral oil.

Software tools are available to conveniently manage DGA data, and to apply sophisticated DGA diagnos-tic algorithms to interpret and present the results in intuitive ways. When these software tools are used in conjunction with DGA monitors and other on-line sensors, asset managers can oversee asset health in real-time and leverage health-index methods to pri-oritize which transformers most merit further investi-gation. Such condition based maintenance programs offer the possibility to make more efficient use of maintenance teams and operating budgets, while at the same time treating transformer faults as early as possible, before costly transformer damage and outag-es occur. | PGI

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32WWW.POWER-GRID.COM

SYSTEM PROTECTION

By Tushar Damle, Jonathan Goldman, Lukas Graber and Chunmeng Xu, Georgia Institute of

Technology, and Matthew Bosworth and Michael Steurer, Florida State University

An estimated 7.6 million people lost power

in Florida, Georgia and North Carolina

during Hurricane Irma. The outages lasted

from a few hours to several days, depending

on the location. Other less devastating

weather events also resulted in a loss of

power to a few hundred thousand people

in Pennsylvania, New York and Michigan,

all in 2017. Utilities across the country are

challenged by weather events and disasters

that create power disruptions, collectively

costing them and their customers billions of

dollars a year. Restoring power to customers

as quickly and efficiently as possible—or,

better yet, reducing the number of customers

losing power—is a top priority for all utilities.

Building a Better Way

Teams From Two Universities Create an Ultrafast Mechanical

Disconnect Switch for Distribution System Protection

A grid that is highly interconnected can restore pow-er to affected areas faster, but interconnecting sub-stations increases the fault current level, exposing substation equipment to higher levels of stress. This means many utilities must upgrade their substation equipment to meet the requirements for higher fault current ratings. In addition, increasing penetrations of renewables contributes to higher levels of fault currents, making utilities reluctant to encourage home owners and small businesses to connect re-newable power sources to their grids. Technologies and devices that limit the fault current enable more resilient grids with a greater share of renewables.

“Fault current limiting devices reduce the stress on grid components, allowing us to keep them working

THE SWITCH PADDLE OF FAST MECHANICAL DISCONNECT SWITCH (ABOVE); CAD MODEL OF THE COMPLETE SWITCH ASSEMBLY (BELOW) – PATENT PENDING

Sources: “A New Class of High Speed Disconnect Switch Based on Piezoelectric Actuators,” IEEE Electric Ship

Technologies Symposium (ESTS), Alexandria, Virginia, 2015; and “Ultrafast Electromechanical Disconnect Switch,”

US Patent application 15/214,015, 2016.

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33WWW.POWER-GRID.COM

SYSTEM PROTECTION

in parallel,” said Sergo Sagareli, a senior engineer at Consolidated Ed-ison of New York, which is working on an initiative to improve current limiting devices.

HYBRID CIRCUIT BREAKER-BASED SOLUTION

A hybrid circuit breaker-based solution is being developed to enable higher fault currents and thus improve grid resiliency. The hybrid circuit breaker-based solution, first proposed by ABB, combines solid state switches with a fast mechanical discon-nect switch that can limit the fault current to two to three times the nominal current and protect the substation equipment that would otherwise not be rated to the higher fault current levels.

In a hybrid circuit breaker, the load current flows through the mechanical switch where losses are low, which is shown as A in the figure above. Upon fault, the current is redirected to the solid-state switch by the opening of the current commutation switch, which is the auxiliary breaker that is shown as B in the figure. The mechanical switch subsequently opens at zero current and the solid-state switch, C in the figure, clears the fault well be-fore reaching the prospecting peak current. Transient switching energy is absorbed in another parallel device, which is shown as D in the figure. The total time taken to clear the fault is expected to be less than one eighth of a power cycle (< 2 milliseconds), which limits the fault current.

The enabling technology for a hybrid circuit breaker is a fast mechanical disconnect switch, capable of opening in a few mil-liseconds or less while also carrying high continuous current during normal operation. A team from the Georgia Tech Plasma and Dielectrics Lab, in collaboration with the Center for Advanced Power Systems (CAPS) at Florida State University and Georgia Tech VentureLab, are working to develop such a fast mechanical disconnect switch. The fast mechanical disconnect switch is an improved version of the so-called fault isolation device, devel-oped by CAPS and North Carolina State University (NCSU) for the FREEDM Systems Center.

The mechanical switch uses a piezoelectric actuator integrated inside a vacuum switching chamber (top of figure at left). Two ce-ramic bushings act as the power terminals on top of the ground-ed chamber. The actuator is controlled from signals outside the chamber though a multi-pin vacuum feedthrough. The actuator has an elliptic shell that amplifies the mechanical response of the piezoelectric stack. The elliptic shell is housed in a vacuum-com-patible polymeric frame to which the outer conductors and mov-ing contact tabs are attached. The switch (bottom of figure at left) uses contacts of optimized geometry and material to maximize voltage withstand capabilities when the switch is in the open

position and to minimize losses during current conduction. Arc quenching capabilities are not required because the hybrid topol-ogy guarantees contact opening at zero current.

“A cost-effective, hybrid combination of the low loss ultra-fast me-chanical switch with series commutating switch, in parallel with the interrupt capabilities of a solid-state switch to limit and clear fault currents, would have great potential as a replacement for traditional breakers and fault interrupting switches,” said John Schaffer, consul-tant and former general manager of G&W Electric Co.’s system pro-tection division. Schaffer, is one of several industry experts involved in the initiative to create and prove the ultra-fast mechanical switch.

The original design developed for the FREEDM Systems Center was optimized for 15 kV distribution grids and rated for 100 amp RMS (ARMS) current with 200 ARMS short-term overcurrent capabil-ity. Upgrades to 600 ARMS continuous current rating are currently being implemented. Contact opening time has been demonstrated to be less than 1 millisecond. Experiments have confirmed that the separated contacts can currently withstand 18kVRMS continuously. Further improvements will aim at increasing the voltage withstand capabilities without sacrificing speed. The disconnect switch will be tested at CAPS’s power hardware-in-the-loop testbed. The test-bed includes several power electronic converters rated up to 5 MW (variable voltage source inverters and modular multilevel cell con-verters) and a real time digital simulator (RTDS). The switch will be tested for its ability to clear faults in both AC and DC distribution systems as a part of a hybrid circuit breaker.

The disconnect switch also has potential applications in pro-tection of DC distribution systems, either as a part of a hybrid cir-cuit breaker or a standalone disconnect switch. The disconnect switch can be used as a hybrid circuit breaker for the protection of DC microgrids and energy storage systems, where the lack of a natural zero crossing during short circuit necessitates fault cur-rent limitation. In addition, the disconnect switch can be used as a stand-alone protection device for all-electric ships proposed by the U.S. Navy. Such ships take advantage of the rapid response of power electronics for fault protection without the penalty of hav-ing to shut down major segments of the electrical system to iso-late a fault. This necessitates using fast disconnect switches in the load carrying branches, in their “breakerless” distribution systems.

The fast mechanical disconnect switch being developed by Georgia Tech and Florida State University has applications in multiple areas because it limits the fault current and enables rapid reconfiguration of the system after clearing the fault. It can enable a greater share of renewable energy sources in the grid and help in faster restoration of power to areas affected by natural disasters. Furthermore, it can increase life expectancy of substation equip-ment by implanting controlled switching schemes. This project is funded in part by the National Science Foundation.| PGI

Fast Mechanical Switch Current Commutation Switch

Solid State Switch

Energy Absorption & Voltage Clamping Device

TYPICAL HYBRID CIRCUIT BREAKER TOPOLOGY WITH THE MECHANICAL SWITCH (YELLOW)

1802pg_33 33 2/2/18 3:55 PM

34WWW.POWER-GRID.COM

PRODUCTS

STORM IMPACT

ANALYTICS SOLUTION

To support utilities, DTN, a provider of

weather insights, launched its new Storm

Impact Analytics solution. Storm Impact

Analytics provides quantitative and

customized damage and outage incident

predictions to help utilities better prepare

for weather-driven outages, restore power

faster and increase service reliability. By

knowing the what, when and where of

each weather-related incident, utilities

can achieve greater decision-making

confidence and deliver a higher level

of customer service. In addition, a vault

of operational intelligence can be used

by all levels of the organization. The

system uses a sophisticated machine

learning-based approach to provide a

set of quantitative predictions. Fully

integrated with DTN’s WeatherSentry®

solution, Storm Impact Analytics also

includes real-time, 24/7 meteorological

guidance, making it a fully operational

and comprehensive storm emergency

preparedness solution. The machine

learning technology “trains” the

solution on how each individual utility’s

infrastructure responds to storms,

using historical weather and the utility’s

own historical outage incidents. It

understands how infrastructure has

responded to past storms including:

• Learning differences in network hardening

• Realizing the age of individual infrastructure

components and maintenance practices

• Factoring in vegetation types and locations,

as well as the impact of tree trimming

This allows it to predict the impact of

forecasted storms on a utility’s network,

including likely damage and outages.

DTN

GO TO WWW.PGIHOTIMS.COM FOR MORE

INFORMATION

SYNCHRONOUS

CONTROLLER

Analog Devices announces the Power by

Linear™ LTC7821, a hybrid step-down

synchronous controller that merges a

switched capacitor circuit with a synchronous

step-down controller, enabling up to a 50

percent reduction in DC/DC converter

solution size compared to traditional

step-down solutions. This improvement is

enabled by a three times higher switching

frequency without compromising

efficiency. Alternatively, when operating

at the same frequency, an LTC7821

based solution can provide up to a 3

percent higher efficiency. Other benefits

include low EMI and reduced MOSFET

stress due to a soft-switched front end,

ideal for next generation non-isolated

intermediate bus applications in power

distribution, datacom and telecom as well

as emerging 48V automotive systems.

The LTC7821 operates over a 10V to

72V (80V abs max) input voltage range

and can produce an output voltage from

0.9V to 33.5V with currents in multiple

10s of amps, depending on the choice of

external components. In a typical 48V to

12V/20A application, an efficiency of 97

percent is attainable with the LTC7821

switching at 500 kHz. External MOSFETs

switch at a fixed frequency programmable

from 200 kHz to 1.5 MHz. The LTC7821’s

powerful 1Ω N-channel MOSFET gate

drivers maximize efficiency and can drive

multiple MOSFETs in parallel for higher

power applications. Due to its current

mode control architecture, multiple

LTC7821s can be operated in a parallel,

multiphase configuration with excellent

current sharing to enable much higher

power applications.

ANALOG DEVICES

GO TO WWW.PGIHOTIMS.COM FOR MORE

INFORMATION

BLUETOOTH COMPLIANT ICS

Toshiba America Electronic Components

Inc. announced that it has added two new

devices to its lineup of integrated circuits

(ICs) that are compliant with the Bluetooth®

low energy standard. The new TC35680FSG

(featuring built-in flash memory) and

TC35681FSG are well-suited to applications

requiring long-range communication,

including beacon tags, Internet of Things

(IoT) devices and industrial equipment.

The new communication ICs support the

full spectrum of data rates required for the

high-speed features—2M PHY and Coded

PHY (500 kbps and 125 kbps)—found in

the Bluetooth 5.0 standard. In addition, the

new devices deliver a receiver sensitivity

level of -105dBm (at 125 kbps) and a

built-in high efficiency power amplifier in

the transmission block that provides up to

+8 dBm transmission power. By adding

5.0-compliant ICs to its extensive lineup,

Toshiba helps companies integrate Bluetooth

low energy products into IoT devices and

addresses the growing demand for high-

throughput, long-range communications.

Based on an Arm® Cortex®-M0 processor,

the new ICs incorporate a 256 KB Mask

ROM to support the Bluetooth baseband

process, and 144 KB of RAM for processing

Bluetooth baseband, stack and data.

Toshiba’s TC35680FSG and TC35681FSG

also feature 18-port GPIOs as interfaces,

which can be set to two channels each

for SPIs, I2C and UART. This allows for

the structuring of systems that connect to

various peripheral devices. These GPIOs

can be set for a wakeup function, 4-channel

PWM, 5-channel AD converter interfaces,

an external amplifier control interface for

long-range communication, and more.

TOSHIBA AMERICA ELECTRONIC

COMPONENTS INC.

GO TO WWW.PGIHOTIMS.COM FOR MORE

INFORMATION

1802pg_34 34 2/2/18 4:01 PM

35

CALENDAR

ADVERTISER PG

HUBBEL POWER SYSTEMS INC 3

DISTRIBUTECH AFRICA 2018 C2

ELECTRIFY EUROPE 2018 C4

ICCI 2018 C3

POWER-GEN INTERNATIONAL 2018 24

DistribuTECH 2018:The industry’s most comprehensive conference

on grid automation and optimization, DER integration

and management, energy storage, T&D engineering

and customer engagement. Feb. 5-7, 2019, New Orleans,

918-832-9265 www.distributech.com

FEBRUARY //////////////////////////////////////////////////

19-21Smart Energy Summitparksassociates.com/events/smart-energy-sum-

mit

AUSTIN, TEXAS

19-23Doble Life of Transformer Seminarevents.doble.com/loat

NATIONAL HARBOR, MARYLAND

25-28TechAdvantage 2018 Conference & Expotechadvantage.org/conference

NASHVILLE, TENNESSEE

Feb. 27-March 1Storage Weekinfocastinc.com/event/storage-week

SAN FRANCISCO

Feb. 28-March 2World Smart Energy Weekwsew.jp/en

TOKYO

MARCH /////////////////////////////////////////////////////////

2-3MIT Energy Conferencemitenergyconference.org

BOSTON

6-9The Work Truck Showntea.com/worktruckshow

INDIANAPOLIS

26-29International Battery Seminar & Exhibitinternationalbatteryseminar.com

FORT LAUDERDALE, FLORIDA

APRIL/////////////////////////////////////////////////////////////////////////////////////

10-11Oracle Industry Connectoracle.com/oracleindustryconnect

NEW YORK

16-19IEEE PES T&Dieeet-d.org/IEEE18/public/enter.aspx

DENVER

18-20Energy Storage Association Conference & Expoesacon.energystorage-events.org

BOSTON

1421 S. Sheridan Road, Tulsa, OK 74112 P.O. Box 1260 : Tulsa, OK 74101 918.835.3161, fax 918.831.9834 www.pennwell.com

SENIOR VICE PRESIDENT, NORTH AMERICAN POWER GENERATION GROUP Richard Baker

PRODUCTION COORDINATOR Rae Lynn Cooper 918.831.9143 raec@pennwell.com

ADVERTISING SERVICES COORDINATOR Cary Shipley 918.831.9438 cshipley@pennwell.com

NATIONAL SALES MANAGER Tom Leibrandt U.S., Canada, International 918.831.9184 fax 918.831.9834 toml@pennwell.com

INTEGRATED MEDIA CONSULTANT Sam Dodson 918.831.9120 fax 918.831.9834 samd@pennwell.com

SENIOR DISTRIBUTECH EXHIBIT & SPONSORSHIP SALES MANAGER Sandy Norris 918.831.9115 fax 918.831.9834 sandyn@pennwell.com

For assistance with marketing strategy or ad creation, please contact PennWell Marketing Solutions

VICE PRESIDENT Paul Andrews 240.595.2352 pandrews@pennwell.com

REPRINTS Jill Kaletha 800-428-3340 x149 jkaletha@mossbergco.com

1802pg_35 35 2/2/18 4:42 PM

36WWW.POWER-GRID.COM

PARTING THOUGHTS

TRENDS

TWEETS

TALK

RRENNNDT

Bitcoins should be called BTUcoins...and everyone is

paying the price, asserts @EnergyCollectiv: http://bit.

ly/2AJpiZC —@ieee_pes

Whatever the [energy] mix will be… decarbonization is happening a lot faster than a lot of us have predicted —@ADSWagenda (Abu Dhabi Sustainability Week)

“Released on September 11,

1977, the Atari 2600 is credited with

popularizing the use of microprocessor-based

hardware and ROM cartridges containing game

code, a format first used with the

Fairchild Channel F video game

console in 1976…” —@ieeeorg

“The 4 most exciting technologies in #energy are: storage for homes &

businesses, hydrogen fuel cells, vehicle to grid, and heat pumps - each

#decarbonize different sectors.” —@SiemensUKNews

“The key to truly smart grids will be IT and telecommunication upgrades that optimize system measurement and monitoring capabilities. This will improve the ability to prevent system outages and reliability/quality impacts from the integration of renewable technology or natural disasters.” —Stephen Persutti,

vice president of utility development for TRC Cos.

“The majority of both small (73 percent) and large businesses (89 percent) say they presently or

in the future plan to implement energy efficiency.” —ZPryme and Ecova: “Utility Business Customer Survey on Energy Management”

“The new U.S. tax regime shouldn’t affect utilities much.

Utilities with unregulated businesses should benefit, but

regulated utilities will simply pass tax savings to customers

through lower energy bills.” —Morningstar Quarter-End Insight on Utilities

“The ISO reluctantly takes these steps and will collaborate with the rest of the funding parties to ensure

continuity of reliability services and to avoid any party being adversely affected financially.”—Steve Berberich, president and CEO of the California Independent System Operator, which gave notice of withdrawing from reliability coordinator Peak Reliability

and announced plan to handles its own transmission system reliability work.

“With renters comprising such a significant segment of the U.S. population today, electric utilities and their partners would do well to create special programs that engage and educate to the specific interests and needs of this group of consumers.” —Patty Durand, president and

CEO of the Smart Energy Consumer Collaborative

“While there is no one-size-fits-all formula for success, electric utility leaders are finding that a steady combination of proactive outreach through a mix of digital, mobile, community events and dedicated account representative touch points can drive a strong positive perception of their brands.” —John Hazen, director of utility practice at JD Power, about new business electric customer survey

showing record highs in satisfaction scores

1802pg_36 36 2/2/18 4:01 PM

Go to pgi.hotims.com for more information.

THIS FAIR IS ORGANIZED WITH THE INSPECTION OF THE UNION OF CHAMBERS AND COMMODITY EXCHANGES OF TURKEY IN ACCORDANCE WITH THE LAW NUMBER 5174

Sektörel Fuarcılık A.Ş. Tel. +90 212 334 69 00

Fax +90 212 334 69 70

Email: info@icci.com.tr

www.icci.com.tr

24TH INTERNATIONAL ENERGY AND ENVIRONMENT FAIR AND CONFERENCE

02-04 MAY 2018ISTANBUL EXPO CENTER, ISTANBUL, TURKEY

THE LATEST ADDITION TO THE POWER-GEN FAMILY OF EVENTS

DELIVERING SMART INNOVATION TO THE TURKISH ENERGY MARKETTaking place in Istanbul, Turkey, and with over 200 exhibitors and over 14,000 attendees, ICCI Powered by POWER-GEN is one event not to miss, providing an international platform where conference, exhibition and B2B meetings run concurrently throughout the 3 days. Hosting the industry’s largest and most prominent players from around the world, ICCI Powered by POWER-GEN incorporates the latest energy and environmental technologies alongside a thought-provoking conference.

ICCI Powered by POWER-GEN is FREE to attend, so make plans today to ensure you join us for the 24th annual edition. Further information can be found at www.icci.com.tr/en.

JOIN US IN ISTANBULWWW.ICCI.COM.TR/EN

For Exhibiting information,

please contact:

Feraye Gürel

T: +90 (212) 334 69 39

M: +90 (532) 612 77 17

E: FerayeG@Pennwell.com

1802pg_C3 3 2/2/18 4:01 PM

19 -21 JUNE 2018 MESSE WIEN | VIENNA | AUSTRIA

BROUGHT TO YOU BY POWER-GEN & DISTRIBUTECH

Looking for answers about Demand Side Response?

At Electrify Europe we take a close look at the markets, the role of aggregators,

operational experiences, and its integration into an energy management plan.

For further information please visit www.electrify-europe.com or contact:

EUROPE

Sophia Perry

T: +44 (0) 1992 656 641

E: sophiap@pennwell.com

WORLDWIDE

Leon Stone

T: +44 (0) 1992 656 671

E: leons@pennwell.com

NORTH AMERICA & CANADA

Jared Auld

T: +1(918) 831-9440

E: jareda@pennwell.com

Owned and Produced by: Presented by:

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DEMAND SIDE RESPONSE DEEP DIVE

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1802pg_C4 4 2/2/18 4:01 PM