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6 EDIST Conference is Positioned for the Future

8 Tacoma Washington, America’s Most Wired City

36 The Case for Advanced Electricity Metering in Texas - Part 1

29 Check Power Quality and Protect Utility Revenues

30 Power Quality Analysis Made Easy

31 Is a Kilowatt Saved Really a Kilowatt Saved?

34 Manitoba Hydro Expands Communications, Information Sharing

14 Modular, Composite Utility Pole wins Ace Award

18 Smart Sensors Enable a Smarter Grid

16 AMEC going into Bruce Power Project with Eyes Wide Open

21 How Infrared Thermography Helps Southern California Edison Improve GridReliability

12 Quebec’s Big Wind Play

45

46

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Issue

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005

in this issueEDITORIAL

SMART METERING

THE HUMAN FACTOR

EFFICIENCIES

MAINTENANCE

ADVERTISERS INDEX

INNOVATIVE TECHNOLOGIES

Electricity Today Magazine is published 9 times peryear by The Electricity Forum [a division of The HurstCommunications Group Inc.], the conference manage-ment and publishing company for North America’s elec-tric power and engineering industry. Distribution: free of charge to North American electri-cal industry personnel who fall within our BPA requestcirculation parameters. Paid subscriptions are availableto all others. Subscription Enquiries: all requests for subscriptionsor changes to free subscriptions (i.e. address changes)must be made in writing to:

Subscription Manager, Electricity Today215-1885 Clements Road,Pickering, Ontario, L1W 3V4

or on-line at www.electricityforum.com.

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PRODUCTS AND SERVICES SHOWCASE

Electricity Today Issue 9, 2005 4

editorial board

BRUCE CAMPBELL

BOB FESMIRE

CHARLIE MACALUSO

SCOTT ROUSE

BRUCE CAMPBELL, LL.B., Independent Electricity Market Operator (IMO)Mr. Campbell is responsible for business development, regulatory

affairs, corporate relations and communications, and legal affairs at theIMO. He has extensive background within the industry and, in particular,acted as legal counsel in electricity planning, facility approval and rateproceedings throughout his career in private practice.

BOB FESMIRE, ABBBob Fesmire is a communications manager in ABB's Power

Technologies division. He writes regularly on a range of power industrytopics including T&D, IT systems, and policy issues. He is based in SantaClara, California.

CHARLIE MACALUSO, Electricity Distributor's AssociationMr. Macaluso has more than 20 years experience in the electricity

industry. As the CEO of the EDA, Mr. Macaluso spearheaded the reformof the EDA to meet the emerging competitive electricity marketplace, andpositioned the EDA as the voice of Ontario's local electricity distributors,the publicly and privately owned companies that safely and reliably deliv-er electricity to over four million Ontario homes, businesses, and publicinstitutions.

SCOTT ROUSE, Managing Partner, Energy @ WorkScott Rouse is a strong advocate for proactive energy solutions. He

has achieved North American recognition for developing an energy effi-ciency program that won Canadian and US EPA Climate ProtectionAwards through practical and proven solutions. As a published author,Scott has been called to be a keynote speaker across the continent fornumerous organizations including the ACEEE, IEEE, EPRI, and CombustionCanada. Scott is a founding chair of Canada’s Energy Manager networkand is a professional engineer, holds an M.B.A. and is also a CertifiedEnergy Manager.

DAVID W. MONCUR, P.ENG., David Moncur EngineeringDavid W. Moncur has 29 years of electrical maintenance experience

ranging from high voltage installations to CNC computer applications,and has conducted an analysis of more than 60,000 various electrical fail-ures involving all types and manner of equipment. Mr. Moncur has chaireda Canadian Standards Association committee and the EASA OntarioChapter CSA Liaison Committee, and is a Past President of the WindsorConstruction Association.

JOHN McDONALD, IEEE President-ElectMr. McDonald, P.E., is Senior Principal Consultant and Director of

Automation, Reliability and Asset Management for KEMA, Inc. He isPresident-Elect of the IEEE Power Engineering Society (PES), ImmediatePast Chair of the IEEE PES Substations Committee, and an IEEE Fellow.

DAVID W. MONCUR

JOHN McDONALD


The fourthannual EDISTC o n f e r e n c e

and Exhibition inJanuary bringstogether engineers,operation profes-sionals, IT profes-sionals, financial andmanagement stafffrom Ontario’s LocalD i s t r i b u t i o nCompanies (LDCs),as well as organiza-tions representingthe supply, manufacturing and servicesectors of the energy industry.

EDIST (Electricity DistributionInformation Systems & Technology) willfeature more than 250 industry people atthe two-and-a-half day event inMarkham, Ontario from January 25-27,with such companies as ABB, BellCanada, Cooper Power Systems,Kinectrics, G.E. Energy and Panasonichaving participated in previous years.

The theme for 2006, “PositioningLocal Distribution Companies for theFuture”, is targeted for engineers, opera-tional, IT and financial professionals,financial and management staff fromOntario’s LDCs., in addition to the com-mercial members representing the sup-ply, manufacturing and service sectors ofthe energy industry.

The program includes a number ofplenary and concurrent sessions dealing

with the most currenttopics in engineering,finance, technology andoperations, includingsmart metering, CDMbest practices, revenueassurance and more.Attendees will be get-ting the latest updateson information technol-ogy, smart metering,CDM best practices,the future of technicalskills training, revenueassurance and more.Sponsored by theElectricity DistributorsAssociation, EDISTalso offers great exhibi-tion and sponsorshippackages for participat-ing companies whowant to display theirproducts and servicesdirectly to their target

markets.Located at the Hilton Suites

Conference Centre at Highway 7 andWarden, you can get more informationon EDIST by going to their website,www.edist.ca

EDITORIAL

EDIST CONFERENCE IS POSITIONEDFOR THE FUTURE

By Don Horne

Photos from last year’s EDIST conference

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ELECTRICITY TODAY 27-09-2005 12:03 Pagina A-Master A


Tacoma boasts one of thelargest publicly ownedtelecommunications infra-

structure systems in the nation,offering more fiber optic connectiv-ity than any other city in the country.Today, Tacoma Public Utilities(TPU) is taking the city’s technolo-gy assets to a new level by estab-lishing one of the first “smart meter-ing” systems in the country. Usingthe city’s wired assets, TPU’s newtechnology will allow customers toremotely monitor power reliabilityand usage, control their utility envi-ronments from anywhere in theworld, and set up pay-as-you-gopayments via the web. With 10,000Smart Meters ready for usemore than 2,200 miles ofdistribution lines, Tacoma isstill leading the nation intelecommunication connec-tivity.

Randy Karr, GatewayProject Manager at TacomaPublic Utilities, says thereare two reasons whyTacoma was prompted toundergo the smart meterproject.

“First, customer ser-vice,” he says. “We wantedmore up-to-the-minuteinformation about outagesand signal quality. We hope to detect andeven fix problems before the customernotices. And second, efficiency – byeliminating manual meter reads, we canreduce manpower requirements.” Withremote disconnects and reconnects, TPUcan reduce truck rolls, thereby savingmoney for their customers.

Deployment ChallengesOne of the biggest technical chal-

lenges was finding a meter manufacturercompatible with their hybrid coax fibersystem HFC. “We have been the firstlarge system to utilize this approach andwe have encountered start-up bugs along

the way,” he says. “We also underesti-mated the back-office systems complexi-ty and especially the details involvedwith interfacing to our SAP billing sys-tem.”

Professionals in the electrical indus-try – specifically those building apart-ment complexes and industrial develop-ments – can learn from TPU’s experi-ence. “We initially missed the fact thatmulti-dwellings sometimes use differentmeters than residential customers,” saysKarr. “Our initial meters were 2S metersand our system has about 50 percent 12Smeters in multi-dwellings. We also had towork with space limitations since multi-

dwellings stackmeters closer togeth-er.” AMR systemsthat switch power offremotely are fairlynew and still indebugging stages ofd e p l o y m e n t .Dedicated staff towork the issues ofmaturing the prod-ucts is a necessity,Karr added. Now that the metersare in place, the nextstep for Tacoma is tofinalize their 10-yearplan to convert alltheir meter plants to

smart meters, as well as workon a “pay as you go.”

Network TransportTacoma Power’s Click!Network was conceived in1992, as Congress beganconsidering electricity dereg-ulation. To remain viable inthe potential new environ-ment, the utility recognized itwould need to upgrade itsservice reliability. Ratherthan rely on paper maps andpush-pins to locate outages,Tacoma Power would need a

state-of-the-art telecommunications sys-tem to monitor its distribution network inrealtime and automatically reroute powerwhen faults occurred. In 1997, after fouryears of detailed research and considera-tion of numerous alternatives –includingunsuccessful attempts of leasing capacityfrom the phone or cable companies –Tacoma Power began building its owntelecommunications infrastructure.

The utility’s use of the networkincludes fiber connections from substa-tions throughout Tacoma Power’s servicearea to the utility’s energy control center

SMART METERS

TACOMA WASHINGTON, AMERICA’S MOSTWIRED CITY

By Regan Stewart

Continued on Page 10

GoTrax is activated as a feature on a Bell wireless subscription plan. Service and features on select handsets within Bell Mobility 1X coverage areas wheretechnology permits. Other conditions, including minimum system requirements may apply. Location fix accuracy may vary. GoTrax is a trade-markof Bell Canada. The BlackBerry and RIM families of related marks, images and symbols are the exclusive properties of and trademarks or registered trademarks of Research In Motion Limited – used by permission.

Introducing GoTrax,™ only from Bell. Now there’s an affordable way to track your mobile workers by locating their wireless devices, like cellphones or the BlackBerry 7250.™ It’s an easy to use, web-basedapplication, so there’s no need for software installation or major hardware purchases. And it works evenin the most challenging urban environments. With GoTrax, you can manage your workforce more efficiently and respond faster to customer service calls.

For more information, call 1 866 371-9747, visit any Bell Worldor Bell Mobility store, or go to www.businessonthego.ca/gotrax

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for monitoring and load management vis-ibility. The telecommunications networkis integral in the utility’s smart meter pro-ject. Tacoma Power is currently deploy-ing residential meters which incorporateboth communications and control fea-tures in a single, integrated meter.

These “smart meters” are capable ofhighly granular remote meter reads,remote electric service connects and dis-connects, remote telecommunication ser-vice connects and disconnects, metertampering detection, and micro-outagedetection. These devices enable prepaidresidential billing, provide access toaccurate and timely information aboutenergy use and should enable the open-ing and closing of accounts with a singlephone call, saving the utility operationalcosts.

The biggest challenges of construct-ing the network included building a mas-sive fiber and coaxial cable system hun-dreds of miles long from the ground up.Tacoma Power crews had to make roomon the utility poles to accommodateanother telecom provider – Click. Clickis now an operating section of TacomaPower. Diane Lachel, GovernmentRelations Manager, Click!Network/Tacoma Power explains,“During that time we experienced politi-cal challenges from a handful of vocalbusiness leaders who did not initiallythink the government should be in a com-petitive business. Telecom and cablefranchise negotiations took a year tocomplete and were required prior todeploying services.” The Telecom Act of1996 requires cities to treat all serviceproviders the same.

Other challenges, Lachel adds,included the often sluggish bureaucracyof being a public entity, receiving neces-sary equipment as a small operator (withthe largest operator in the country as adirect competitor), stalls in negotiatingcontracts with program suppliers whowere owned by our competitor as well asvandalism in the field.

Click capitalized on the fact that nei-ther wire line competitor had upgradedtheir infrastructure in decades. Theydesigned a robust and fully redundant

infrastructure and built a state-of-the artnetwork capable of multiple applications.The company even asked the utility’scustomers’ what they wanted to see ontheir TVs as well as what were they will-ing to pay for it.

“We’ve constructed TacomaPower’s telecommunications networkand deployed commercial services inapproximately 60 percent of TacomaPower’s total 180 square miles of servicearea,” Lachel says. “The smart meterproject is in its early stages with slightlymore than 3,500 smart meters deployed.”

Tacoma Power has 155,000 total cus-tomers.

Prior to Tacoma Power’s investmentin Click! Network, businesses spent 12 to18 months to install telephone lines. TheTacoma/Pierce County area was under-served because the phone company andcable company had limited capital.Residents only had access to a 25-year-old cable plant with 33 channels and nointeractive services.

Regan Stewart is a freelance writerbased out of Texas.

SMART METERS

WiredContinued from Page 8

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Recently, the University ofQuebec’s Rimouski campusplayed host to a conference on

wind power. Falling immediately afterthe Canadian Wind Energy Association’s(CANWEA) annual meeting, and locatedin Quebec’s remote Magdalen Islands, themeeting was anticipated to be a relativelysmall event with around 150 attendees.Nearly 250 showed up.

The surprising boom in attendance isindicative of the buzz being generatedabout wind power in Quebec these days,and with good reason. Quebec is blessedwith an abundance of wind resources —as much as 100,000 MW within 25 kilo-meters of existing transmission linesaccording to a recent study. It is furtherestimated that up to 4,000 MW of windcould be added to Hydro Quebec’s net-work by 2015 without causing significantsystem constraints.

The provincial government has takenbold steps in recent years to boost thedevelopment of wind power in Quebec,mandating in 2003 that state-ownedHydro Quebec (HQ) acquire 1,000 MWof new wind generation capacity, andrecently issuing a second decree for anadditional 2,000 MW. Quebec is alreadypoised to overtake Alberta as theCanadian leader in wind energy, and withthese new initiatives the region is lookingto become a major player in the globalwind industry. But the motivating forcebehind these moves has as much to dowith local economics as it does with fueldiversity and environmental concerns.

Quebec sees wind power as a meansto multiple ends. It provides the provincewith new sources of emissions-free gener-ation to support economic growth, but italso stimulates that growth directly.Unlike other areas where “jobs” and“emissions” usually involve an unhappytradeoff (think coal mining), Quebec hasused local content provisions in therequests for proposals (RFPs) issued byHQ to ensure that the development of thearea’s wind resources will also createlocal jobs.

This is especially meaningful for theGaspe region, a windswept peninsula inthe Gulf of St. Lawrence that has fallen onhard times in the wake of downturns in themining and fishing industries on which itrelied for many years. Hydro Quebec’sfirst RFP stipulated that 40-60% (depend-ing on timing) of the costs associated withthe turbines themselves must be incurredwithin the Gaspe itself, while 60% of theproject costs in total be spent in Quebec.A stringent requirement, to be sure, but itdidn’t stop a swarm of developers andmanufacturers from going after the busi-ness. In fact, the first RFP precipitatedmore responses, and lower prices, thananticipated with eight projects beingawarded for a total of 990 MW of powerto be sold at 6.5 cents per kWh. And yes,that’s 6.5 cents Canadian.

Will wind-related manufacturing jobsbe enough to turn the Gaspe’s economyaround? Probably not, but the idea thatwind can have a positive impact on a localeconomy is one that deserves more atten-tion, especially in manufacturing centerslike the “rust belt” of the US.

Still, if the Gaspe — and Quebec ingeneral — is to become a Mecca for thewind industry, the companies that set upshop there will have to stay after the workfor HQ’s initiative is complete. For that tomake sense, they will have to export, andthat means competing successfully in theworld market.

That’s the position of various indus-try observers, including CANWEA.While praising Quebec for its forwardthinking approach to wind power, theorganization was also concerned that thelocal content provisions would be toomuch of a good thing. The provincialgovernment seems to have taken this intoaccount in the second RFP by reducingthe Gaspe-specific requirement to 30% ofturbine costs. The province-wide require-ment, however, remains at 60%.

However, towers, turbines and bladesare not the only export Quebec has tooffer when it comes to wind energy. HQ’sextensive experience with hydroelectrici-

ty — and now its expertise in integratingwind with a large hydro system — couldpay dividends down the line as well.

Aggregation of wind farms can domuch to mitigate intermittency, but thefact remains that wind is an inherentlyvariable power source. Conversely, hydroresources are extremely predictable, andthey can provide a perfect compliment towind generation. Hydro plants can becontrolled precisely to follow the smallvariations in wind output while still avoid-ing the emissions and volatile fuel costsassociated with gas-fired plants. As windenergy continues to grow, the use of hydropower to facilitate its integration to exist-ing grids is likely to grow with it. Thiswill require specialized expertise, a nichethat Quebec is positioning itself to filltoday.

If the current initiative can be par-layed into sustained businesses that con-tinue on after the province has brought itsnext 2,000 MW online, then it seems safeto declare the approach a success. At whatpoint, though, does the benefit of localcontent requirements become a liabilityfor global competition? Manufacturers ontheir way to eastern Canada now to supplythe eight projects awarded under the firstRFP will soon have to start looking at howto make money in the export market.Otherwise, the last rotor blade shipped forRFP2 could be the last one shipped, peri-od. Clearly, Quebec’s play for wind jobs isa gamble, but the benefits of 3,000 MW ofwind generated power will accrue formany years after that last blade rolls out ofthe factory.The views expressed by Bob Fesmire arenot necessarily those of ABB.

THE HUMAN FACTOR

QUEBEC’S BIG WIND PLAYBy Bob Fesmire, ABB


Alberta’s ResinSystems Inc.(RS) won the

Most CreativeApplication ACEaward for its work incomposite technology.

It was a 75 footRStandard modularcomposite utility polethat earned the compa-ny the award, demon-strating the most cre-ative application andinnovative use of com-posite materials.

Given by theAmerican CompositesM a n u f a c t u r e r sAssociation (ACMA),the world’s largesttrade association serv-ing the compositesindustry, the Awardsfor CompositesExcellence (ACE)Product Showcase andCompetition, recog-nizes technologyachievement andexcellence in compos-ites manufacturing.The award was pre-sented during the 2005ACMA Compositesshow in Columbus,Ohio, recognizingRS’s innovation andcommitment to theadvancement of com-posites.

RS operates in thecomposite materialproducts marketplaceand provides engi-neered solutions thatare developed with its proprietary inputmaterials, equipment and processes.

The foundation of these solutions isbased on the company’s patentedpolyurethane Version(tm) resin system.

The company’s engineered solutions aredeveloped and implemented in three dis-tinct technology platforms, one of whichis filament winding, which has resultedin the development and production of the

RStandard modular composite utilitypole.

For the latest on the company’sdevelopments, click on ‘Latest News’ onwww.grouprsi.com.


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Smarter.


The announced restart ofBruce A Units 1 and 2 inOctober really began in

April of 2003 when Bruce PowerAMEC began taking a hard lookat the feasibility of refurbishingthese mothballed reactors.

“It’s been two years in thepreparation, and over 18 monthssince we we got involved in someof the preliminary work, lookingat different project models,” saysKevin Routledge, Project Directorand President of AMEC NNCCanada Limited (AMEC NCL).“It has been very demanding, butalso is very exciting to beinvolved in such a challengingproject.”

AMEC, an international projectmanagement and services company, hasbeen was selected by Bruce Power LP asthe project manager to restart two ofBruce A nuclear reactor units that wereshutdown in the mid-1990s.

As the project leader, Mr. Routledgebrings a wealth of experience to the job.

“I have 32 years (experience) in thenuclear industry with a UK (UnitedKingdom) company known as NNC(now AMEC NNC), and we built all thereactors in the UK and ones for Italy andJapan.

“We’ve been involved in a numberof reactor refurbishment projects over theyears in Russia, Lithuania and theUkraine, and I’ve worked on just aboutevery reactor type in the world.”

The $4.25 billion investment pro-gram for Bruce Power is being conduct-ed under the auspices of Bruce ALPOntario Power Generation.

The total investment includes $2.75billion to restore Units 1 and 2, whichhave been down since the mid-1990s.

“We will be working on them in par-allel, and expect them to be back on thebars by 2009,” he says.

The remaining $1.5 billion will bespent on refurbishment of Unit 3, andwith $350 million of that allocated to

replace the steam generators on Unit 4. AMEC was hired to manage the pro-

ject and keep costs under control, and hasinvested a half-billion dollars of its ownmoney. Major investors in the project areCalgary-based TransCanada andOMERS, one of the country’s largestpension plans, both shareholders inBruce A LP.

As part of this contract worth up to$510 million, AMEC is mobilizing ateam onsite to undertake project manage-ment, contract management and con-struction management, on behalf ofBruce Power, as well as to provide criti-cal services for the contractors undertak-ing modification work on the plant. Inaddition to the project management ser-vice, AMEC’s proprietary project man-agement system Convero will be used onthis project.

Although the capital cost for therefurbishments will be covered by BrucePower, a “risk and reward sharing sched-ule” will have taxpayers liable for 50 percent of cost overruns of up to $618 mil-lion on the project and a 25 per cent sharebeyond that.

And AMEC is all too aware of theneed to keep a handle on cost overruns.

“It is a very legitimate concern, costoverruns,” says Mr. Routledge. “They

(the nuclear industry) haven’t been verygood at keeping delivering projects ofthis type to budget and schedule costsdown. The industry is good at sharinginformation, and the information we’vebeen studying from previous projectsmakes us confident of getting the out-come we need.”

The cost to build the province’s con-troversial Darlington nuclear stationnearly tripled during the 1980s to $14billion, and Ontario Power Generation’sefforts to restore Unit 4 at the PickeringA facility cost $1.25 billion, almost threetimes the original projected cost.

“Some of the restarts were beguanwithout the preparation being done; thecontracts hadn’t been put in place,” hesays. “We have done a great deal of duediligence in putting the contracts inplace.

“There is always a degree of uncer-tainty,” admits Mr. Routledge. “Wewon’t really know everything until webegin opening up the reactors and seeingwhat is in there.”

Once completed, the refurbishedunits will earn Bruce 6.3 cents per kilo-watt-hour, well above the 4.9 cents perkWh OPG received for its nuclear power

MAINTENANCE

AMEC GOING INTO BRUCE POWER PROJECTWITH EYES WIDE OPEN

By Don Horne


this summer, but less than the averageelectricity costs this year of 6.8 cents perkilowatt-hour.

Canada generates 12.5 per cent of itselectricity from nuclear. Its last reactorcame on-line in 1993. Ontario is thelargest nuclear market, with 20 ofCanada’s 22 reactors. There is a growingmarket to bring mothballed reactors backinto service in order to meet demand forenergy and the provincial government’scommitment to phasing out coal-firedstations. All of its operating reactors willhave to undergo life extension/refurbish-ment and it is estimated that $20 billioncould be spent over the next 15 years.

“The Candu reactor is a good one,and in the early days it was the top per-former in the world bar none,” says Mr.Routledge. “But it has run into life issues,specifically the horizontal pressure tubesthat require replacement every 25 years.”

In comparison, he cites the recent

technological improvements made in theUnited States, especially in the field oflight water technology, are dramaticallyimproving reactor life by upwards of 60years.

“The ACR (Advanced CanduReactor) has moved away from heavywater and uranium to enriched fuel andlight water - like the new American reac-tors,” he points out. “But the existingCandus are still solid performers.”

In terms of funding, the majority ofCanada’s reactors are owned by provin-cial utilities. Eight of the reactors inOntario are leased to Bruce Powera pri-vate company and the cost of bringingtwo of these laid up reactors back onlinewill be funded by its shareholders. It willalso be necessary to extending the oper-ating lease it has with Ontario PowerGeneration by 25 years, which could be amodel for the future. New BrunswickPower has decided to retain ownershipand management of its reactor in the pub-lic sector, and is proceeding with itsrefurbishment.

The AECL is currently making a

decision whether to lease its nuclearpower station to a private company so itcan be refurbished, or close it down andreplace it with a new nuclear or conven-tional plant.

As Mr. Routledge sees it, the optionsof meeting demand and abiding by theKyoto Protocol leave few options.

“Essentially there are only two waysto do it, and only nuclear offers a largeimpact in meeting electricity generationrequirements, while reducing carbondioxide emissions,” he says. “And theother way to significantly eliminateemissions is to put an end to traffic - andno one is going to stop driving.”

The refurbishments will boostBruce’s total nuclear contribution inOntario to 6,200 megawatts - enough topower about 25 per cent of the provinceon a typical day.

The plan is designed to help addresspotential shortages of electricity. Theprovince needs to fix or replace some25,000 megawatts of electricity genera-tion by 2020.

ET

17Electricity Today Issue 9, 2005

Nynas Canada, inc. Telephone: (905) 804-8540. E-mail: [email protected] www.nynas.com

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As the demand for electricityincreases, the electric utilityindustry is faced with many chal-

lenges to supply the high quality, reliableenergy demanded by the sophisticatedindustrial and consumer markets. Afterthe recent blackouts, the industry is evenmore aware that the aging transmissionsystem requires huge capital invest-ments, which puts large financial burdenson the public and private energy suppli-ers.

However, innovative technologiesare emerging to help the grid evolve in acost-effective manner in order to meetthe power consumption needs of modernsociety. Efforts put forth by the UnitedStates Department of Energy and the US

congress have led to the formation ofcoalitions, such as the GridWiseAlliance. These groups are visionary,creating the architecture for the newsmarter power grid. Investment intolong-term R&D has proven fruitful, pro-ducing immediate technological benefitsto the utility industry. This article inves-tigates the innovative technologies devel-oped by Power Measurement, a sub-sidiary of Schneider Electric, that direct-ly address the requirement for increasedvisibility and monitoring on the gridthrough the use of easily deployed smartsensors.

The technology focuses on the abili-ty for utilities to deploy, cost effective,high-accuracy, wireless high voltage sen-

sors that increase grid observability andenable true wide area monitoring systems(WAMS).

NEW PARADIGM FOR WIDE AREAMONITORING SYSTEMS

Increased reliability is directlyaffected by the amount of visibility andmonitoring within the power system.Near real-time collaboration betweenutilities interconnected on the same gridhas historically been challenging. Afterthe effects of the blackout in the westernUnited States in 1996 and, more recently,after the blackout in the northeast inAugust 2003, utilities and system opera-


Fig. 1. Wide Area Monitoring System (WAMS) offering a hybrid system of existing conventional monitoring and innovative new HVSensors.


SMART SENSORS ENABLE A SMARTER GRID

By Paul Doig, Power Measurement

tors realize the importance of wide areamonitoring systems (WAMS). These sys-tems are still in their infancy with rela-tively few sensors placed across variousregions in the US and Canada. The exist-ing sensors monitor voltage stability andprovide this information to systemsresponsible for the reliability of the inter-connected utility grids. Increased fundingfrom the utilities and government hasspawned a reawakening of these types ofsystems. As the requirement for systemreliability increases, utilities are underpressure to increase their monitoringcapabilities and need to install manymore sensors.

A concept, known as synchronizedphasor measurement, is based on collect-ing GPS time-synchronized data frommultiple points on a wide area grid toprovide real-time visibility of voltagestability on the power network. The IEEE1344 Synchrophasor standard providestechnical details on the methodology toachieve highly-accurate, GPS time-syn-chronized phasor information. This sys-tem relies on the synchronized phasormeasurements to be transmitted in real-time to head-end system control centersthat can process and analyze the informa-

tion to make mission critical decisions toimprove system reliability.

The existing synchrophasor mea-surement solution is based on embeddingthis monitoring capability in convention-al advanced metering, digital relayingequipment or specially designed phasormeasurement units (PMU). This solutionuses existing instrument transformerinfrastructure or requires that new equip-ment be installed to provide monitoringat these key monitoring points.

The technology from PowerMeasurement is a unique paradigm offer-ing a hybrid of existing metering pointswith new high-voltage (HV) sensors, asshown in Fig.1. The new HV sensors pro-vide cost-effective, easy, clamp-on instal-lation and wireless integration for previ-

ously unmonitored pointson the grid.

Having the ability toquickly install a sensor onan HV transmission line orwithin an HV substationgreatly enhances visibilityof network monitoring.The HV sensor provideshigh accuracy GPS time-synchronized phasor mea-surements that are wire-lessly transmitted, viasatellite, cellular, orlicensed RF radio back to acentral information system

controlling the real-time operations ofthe grid.

Fig. 2 shows the various componentsof the HV sensor. This technology is selfpowered and designed to be installed liveon HV systems up to 765 kV. Its highlyaccurate, actively compensated split-coreCT and its electric field voltage sensorprovide RMS phase and magnitude dataover the wireless link back to the controlcenter. The type of accuracy from thisHV sensor is not achievable through theconventional instrument transformers–based methodology.

The industry standard for synchro-nized phasor measurements calls foraccuracy of 0.1 degree, however, the


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SensorsContinued from Page 18



instrumentation currently providing thisdata is connected to the secondary wiringof instrument transformers that are man-ufactured to be no better than 1-2% accu-racy. By using a sensor that bypasses theexisting infrastructure and is mounteddirectly and easily at the desired moni-toring point, this provides a leap forwardin technology that immediately con-tributes to the ability to improve theoverall reliability of the power grid.

SYSTEM ACCURACY VERIFICATIONAND RECLASSIFICATION

As mentioned earlier, the conven-tional systems for grid reliability moni-toring rely on advanced metering, digitalrelays and dedicated PMUs to providetime synchronized phasor data. However,the weak link is typically the perfor-mance of the current transformers (CTs)and potential transformers (PTs) that areproviding the analog signals to the highaccuracy instrumentation. Withoutknowing the true accuracy of the entiresystem, system operators cannot reliablydepend on these existing WAMS to makemission critical decisions.

Power Measurement has developeda system, based on the HV sensor tech-nology, that can accurately verify andreclassify existing instrument-class cur-rent transformers while installed andoperating in the field. Inherent errors inphase angle and ratio lead to overall sys-tem errors when calculating synchro-nized phasor data. For those sites whereexisting systems already provide data, itis critical to understand the entire accura-cy of the system. Fig.3 illustrates the sys-tem that is being deployed in substationsin British Columbia, Georgia and NewYork.

The HV sensor acts as the high accu-racy reference sensor, known as the pri-mary sensor, that is traceable to NISTstandards. The primary sensors aremounted live, one on each phase, on thehigh voltage bus within a substation. TheCT under test that is providing analogsignals for the instrumentation is con-nected to a highly accurate advancedmeter. The measurements from the pri-mary sensors are wirelessly streamed andcollected by a PC that is simultaneouslycollecting data from the meter connectedto the secondary wiring of the CT undertest.

The PC compares the GPS time-syn-chronized data from both the primarysensor and the meter and calculates the

error in phase angle and ratio for the CTunder test. Having this error informationprovides insight into the true accuracy ofthe overall measurements used for gridreliability monitoring. With this informa-tion, the accuracy of the CT can bedynamically corrected by programmingthe advanced meter with the necessaryerror characteristic curves. In realtime,the meter corrects for inherent errors inthe CT and simultaneously providestime-synchronized data to the controlcenter to provide information to ensurethe reliability of the grid is maintained.

This unique system completes thehybrid model for wide area monitoring.The ability to verify and reclassify instru-ment transformers while operational inthe field minimizes system downtime,increases system accuracy and improvesthe overall reliability of the grid.

CONCLUSIONThe combination of the highly-accu-

rate HV sensor and the ability to improvethe overall accuracy of existing monitor-ing sites provides a solution that increas-es the visibility for operators controllingthe grid. By providing the industry withthe ability to increase observability of thepower system, the smart sensors enable asmarter grid and accelerate improve-ments in overall grid reliability.


Fig. 3. Accuracy verification and CT reclassification system to increase the overall accuracy of the monitoring point on the grid.Improvements in accuracy provide more reliable data by which operators can effectively improve the control and reliability of the entirepower grid.

SensorsContinued from Page 19

The InfraredT h e r m o g r a p h yInspection program

at Southern CaliforniaEdison has been fully inte-grated into their predictivemaintenance protocol at alltheir facilities. This articlewill provide an overview ofthe program.

A BRIEF OVERVIEW OF SOUTHERNCALIFORNIA EDISON

SoCal Edison services more than 4.1

million customers in a 50,000 squaremile service territory in SouthernCalifornia with a peak demand of21GVA. Our 80 GVA installed capacity is

delivered through 858 substa-tions in which the equipmentcomplement includes:• 900 substation busses• 3,300 power transformers• 10,800 circuit breakers ratedfrom 500 to 2,400 Volts

OVERVIEW OF THE SUBSTA-TION CONSTRUCTION AND

MAINTENANCE DEPARTMENTFigure 1 is a structural chart of our


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HOW INFRARED THERMOGRAPHY HELPSSOUTHERN CALIFORNIA EDISON IMPROVE

GRID RELIABILITYBy Bob Turnbull and Steve McConnell, Southern California Edison

Figure 1. Our organization chart



organization headed by Mr. BobTurnbull, Technical Supervisor ofSubstation Construction andMaintenance Support Services. The heartof our controlled PdM program is thecomputer-based PassPort, which is thename for our Work Management System.

Maintenance Business Systems dataand analysis personnel provide:

• Substation Construction andMaintenance web-site technical lead anddevelopment

• PassPort Work ManagementSystem maintenance data

• Real-time KPI (key performanceindicators) status

• Transporting and management ofdata

• Data communications systemsarchitecture and database structure

Technical Field Support personnelprovide:

• Installation, operation and mainte-nance recommendations, equipment fail-ure analysis and reports and on-line oilfiltering and Morgan Schaffer monitor-ing for transformers, reactors LTCs (loadtap changers) and oil-filled CT/PTs (cur-rent transformers/voltage transformers).

• Installation, operation and mainte-nance recommendations for power cir-cuit breakers and GIS (gas insulating sys-tems).

• Maintenance cost factors providedby the equipment specification teammember

• Capital replacement strategy pro-vided by the transformer resource man-agement team member

• Equipment problem resolution andsupplier performance tracking by theABB (Asea-Brown-Boveri) circuitbreaker team member

• Resource manual, SF6 residualcredit and new gas processing equipmentprovided by the SF-6 sulfur hexafluorideinsulating gas) gas resources team mem-ber

On-line Monitoring personnel pro-vide:

• On-line monitor links to ourPassPort Work Management System

• Development of response timerecorder replacement

• On-line equipment monitoringtechnical lead analysis and on-line moni-

tor data

OUR PREDICTIVE MAINTENANCEASSESSMENT PROGRAM

The mission of our PdM assessment(PMA) program is to improve and opti-mize grid relia-bility throughthe deploymentof a multidisci-plinary diag-nostic programof equipmentm o n i t o r i n g .With all theseelements inplace, and bymeans of ourP r e d i c t i v eM a i n t e n a n c eAssessment (PMA) reports we have con-sistently demonstrated and documentedfailure avoidance and cost avoidance.The Infrared Thermography Inspectionprogram in particular has been most dra-matic in this regard, as shall be demon-strated by examples given later.

The importance of “selling” the pro-gram to team members as well as to man-agement cannot be emphasized enough.While management’s major concernsinvolve meeting business goals andmaintaining profitability, the goals of theteam members revolve more around jobsatisfaction, recognition of contributionby management and personal enrichmentand advancement.

Field personnel also benefit by thesuccess of the program. Frequent system-atic inspections, meaningful findings andtimely maintenance and repair optimizepersonnel and facility safety, minimizedown time and enhance the job satisfac-tion of field operating personnel.

Most critical to our program isemphasizing the concept of a “teameffort”. Effective communication amongteam members is essential. The need to“close the loop” on any finding mustremain foremost in the minds of all teammembers.

THE PMA PROCESS – CLOSINGTHE LOOP

The PMA process begins with regu-larly scheduled inspections at locationsdesignated by the program managers andsupplemented, on occasion, by specialrequests from the field. The technicalspecialists, such as the IR thermogra-phers, perform the station inspectionsand determine the criticality of each find-

ing, assigning a severity level to eachdetected abnormality. These levels, in thecase of infrared thermography, are deter-mined, for the most part, by the maxi-mum detected temperature rise over apredetermined reference temperature,

with Level 1 being themost critical and requiringthe most immediate atten-tion. The severity levelsare defined as follows:

Critical problem-prioritylevel 1

Any problem that is iden-tified as a safety hazard, oran immediate threat to gridreliability.

Identified through the useof diagnostic analysis and

inspections.Action required: repair immediately.Foreman/electrician to make deci-

sion and take immediate correctiveaction to relieve the problem. Notifysuperintendent and program manager assoon as possible.

Note: the corrective action may be inthe form of switching to relieve load,jumper out a disconnect switch, repair orremove equipment from service, etc.

Serious problem-priority level 2A problem that has the potential to

develop into a hazardous condition andaffect grid reliability. Identified throughthe use of diagnostic analysis and inspec-tions.

Action required: repair in the imme-diate future.

Foreman/technical specialist shallperiodically monitor until repaired.Technical specialist notifies supervisionand submits a written report.Foreman/program manager to establishpriorities and schedule at monthly fore-men’s planning meeting.

Note: this type of problem will pro-gressively worsen.

Intermediate problem-priority level 3A problem that is identified as no

immediate threat to personnel or gridreliability.

Identified through the use of diag-nostic analysis and inspections.

Action required: schedule the repair.Foreman/program manager to estab-

lish priorities and schedule at monthlyforemen’s planning meetings.

GridContinued from Page 21


The elements of a PMAprogram are:• PdM technical lead• Maintenance initiatives• Infrared diagnostics• Acoustical diagnostics• Vibration analysis• Technical reporting• Technical recommendations

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Note: this type of problem is less likely to be immediate-ly detrimental to personnel or to the grid.

Minor problem-priority level 4A problem that is identified as requiring routine attention

or maintenance. Little probability of physical damage.Identified through the use of diagnostic analysis and inspec-tions.

Action required: repair as part of regular maintenance.Foreman to establish priorities and complete repairs as

time permits.Note: this type of problem is very unlikely to be detri-

mental to personnel or to the grid.

The technical specialist then inputs the data into the WMSfor the creation of field reports and maintenance repair workorders and the WMS generates the formal reports and workorders. The technical specialist also notifies the field mainte-nance crews directly when there are any severity Level 1abnormalities detected.

Acting on the severity Level I abnormality report, theappropriate foreman generates and releases validation sheetsdirecting repair crew (electricians) to perform the indicatedrepairs. The crew completes and documents the repairs, thesite is reinspected and the foreman closes the work order and

enters the repair data in the WMS.All PMA findings are discussed during regularly sched-

uled monthly workload meetings attended by team personnelfrom all groups. Cost avoidance reports generated for all Level1 abnormalities and repairs are discussed at these meetings.

Information for reporting trends to management is derivedby querying the WMS database. In this way reports are pre-pared from the PMA process for assuring continuing manage-ment support.

EXAMPLES OF FINDINGS USING IR THERMOGRAPHYWe are currently using an Inframatrics model PM 295

uncooled-microbolometer based infrared camera. We employthree (3) Level II certified infrared thermographers. A fourththermographer is currently in training.

We inspect a wide variety of operating equipment in oursubstations, including transformers, circuit breakers, bushings,disconnects, fuses, roto-switches, secondary current termina-tions, potheads, station batteries and relays. The following areillustrations of some of the abnormalities detected.

1. Hot battery terminalA hot connection was detected on a battery terminal at our

Anita Substation as illustrated in Figure 2. A rise of greaterthan 1°C is considered extraordinary in this type of equipmentand required immediate attention.

2. Overheated fan controlcircuit terminals

At our San BernadinoSubstation, the 1AA bank fancontrol circuit exhibited 2overheated terminals, asshown in the thermogram ofFigure 3. The terminal at theleft exhibited a rise of 135°Cand the one at the right exhib-ited a rise of 153.6°C.

3. No oil flowing through transformer radiatorThe thermogram of Figure 4., taken of a transformer bank

at our Center Substation, illustrates the effect of the oil flowbeing shut offfrom the radia-tor at the right,resulting in a ∆Tof greater than20°C.

4. Overheatedtap changer

The tapchanger shownat the center ofthe thermogramof Figure 5,taken at our Elsinore Substation, was measured to be morethan 7°C hotter than the main tank (shown at the left).

5. Hot bushing rod


GridContinued from Page 23


Figure 2 Hot connection atbattery terminal (top)

Figure 3. Fan bank control circuit with 2overheated terminals

Estimated sav-ings in costavoidance are inthe millions ofdollars per yearfrom the IR ther-mography pro-gram alone, farexceeding thecost of the equip-ment and thetraining of our

thermographers. Clearly, in terms of “bang for the buck” IRcomes out way ahead.

2. Where we gofrom here?

It hasbecome apparentthat the combina-tion of incorpo-rating infraredimaging camerasinto the PMA,and meticulously training our personnel in their operation haspaid off in terms of avoided down time, avoided repair costsand enhanced safety for our operating personnel and equip-ment.

A hot bushingrod, detected at ourSantiago Substation,is shown in the ther-mogram of Figure 6.This bushing rod(lower center) had ameasured temperatureof 93.7°C, which wasmore than 60°C hotterthan the referencepoint shown at theupper left.

6. Low oil level indication

A measured tem-perature difference ofgreater than 10°Cresulted from the lowoil level in the radia-tor at the left of thethermogram of Figure7, taken at our SierraMadre Substation.The radiator at theright, with normal oilflow is at a measuredtemperature of 31.6°Ccompared to the18.9°C reading takenon the left-hand bank.

7. Hot fuse clipsSeveral hot fuse

clips appeared on thethermogram of Figure8, taken on the mainDC fuse panel at ourAnita Substation. Asindicated in the ther-mogram, the clipsmarked from left toright exhibited ∆Ts of7.2°C, 4.6°C and3.9°C respectivelyabove the 28.0°C reference.

SUMMARY: WHAT WE HAVE DONE TO DATE ANDWHERE WE GO FROM HERE

1. Cost avoidance benefitsThe “bottom line” in any PdM program resides in the cost

avoidance results. From 1998 to the present we have inspected450 substations with our multidisciplinary assessment pro-gram. Of the more than 3000 real anomalies detected and cor-rected over this period, more than 1500 (about 50%) weredetected by means of infrared thermography. Table 2 illustratesthe results by severity criteria over this testing period.


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Figure 4. The effect of oil being shutoff from the radiator at the right

Figure 5. Tap changer (center) mea-sured to be more than 7°C hotter thanthe main tank (left)

Figure 6. Hot bushing rod (center)measured to be more than 60°C hot-ter than reference bushing

Figure 7. The low oil level in the lefthand transformer bank results in no oilflow through the radiator

Figure 8. Hot fuse the clips exhibited ∆Ts of7.2°C, 4.6°C and 3.9°C respectively abovethe 28.0°C reference

Table 2. Anomalies detected from 1998 tothe present in 450 substations inspected

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In a competitive envi-ronment, electric util-ities are finding that

power quality testing canbe a key part of their cus-tomer satisfaction strate-gy. A utility that offerscomprehensive powerquality analysis canimprove safety, customerservice and revenues.

Fortunately, thereare high-accuracy powerquality test tools nowavailable that make thetask simple and straight-forward. The three-phaseanalyzers that techni-cians use to measurepower factor and trendpower quality now offeruser-settable ratios fordisplaying readings as ifmeasuring at the primaryside of PTs and CTs. They also verifyrevenue meters.

This alone represents a substantialrevenue opportunity. Enough revenuemeters are out of tolerance that a 2001Electric Power Research Institute studyestimated meter-related losses at $5 mil-lion to $20 million per year for a medi-um sized U.S. utility.

Using a multi-purpose analyzersuch as the Fluke 430 Series, for exam-ple, allows utility technicians to offermore customer services in less time andquickly audit revenue meters duringeach site visit.

STOP GIVING AWAY POWERA simple test can verify that the

customer meter is reading correctly.This is important in heavy use environ-ments (shopping malls, industrial users,etc.) and in any areas where the powerquality might be poor. Energy metersare optimized to work under certainconditions. Any change in those condi-tions can cause the meter to work incor-rectly, resulting in the customer payingfor more than he uses (poor customer

service) or less (lost revenue to the util-ity).

Verification with the new breed ofpower quality tester is similar to a hand-switch verification and can quicklyuncover tolerance problems. On newanalyzers, technicians use a softkey toconduct the test, with no configurationor accessories needed. The verificationcan be performed on any electro-mechanical meter or electronic meterthat has an indicator or rotating disk.“Using this energy feature takes about30 seconds with just five button press-es,” says Fluke Electronics Canadaproduct manager, Colin Plastow.

STOP POWER POLLUTION ANDBUILD REVENUES WITH PRE-EMPTIVE

TROUBLESHOOTING Large industrial/commercial users

often cause poor power on the grid,resulting in complaints from theirneighbors. Using power quality testingon the front line can identify the culpritand allow you to correct problemsquickly and improve your reputationwith other users.

There’s no reason why a utility can-not pre-empt such problems by per-forming power quality analysis as a cus-tomer service. Many already sendpower quality specialists to a customersite, where they monitor power at themeter, analyze the data, write a report

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and make recommendations.Utilities that offer this ser-vice have identified a newrevenue source – installingthe recommended solution.

RESOLVE DISPUTESBEFORE THEY HAPPEN

Good power qualitytesting programs are goodinsurance. Utilities havestandards for minimumpower quality on the grid.Customers can hold them tothese standards through awritten agreement. Powerquality analysis can verifythat a customer’s power ismeeting the minimum stan-dard as soon as you receive acomplaint, but before is obviously better.

Taking a snap shot of power qualitybefore and after connecting a new cus-tomer to the grid provides useful data inthe event of a dispute. Keep the informa-tion on file and you will be able to presentan accurate record of what the power

looked like at the time of connection.If a customer is having a problem

with electronic equipment, the powerquality analyzer can quickly showwhether or not the utility is causing theproblem.

Some handheld three-phase powerquality analyzers are rated for useat the service entrance and will

trend data easily, without setup. To sup-port detailed yet efficient assessmentsof substations and customers’ power,new analyzers:

• Measure voltage, current, fre-quency, power, power factor, powerconsumption (energy), unbalance andflicker, harmonics and inter-harmonicson all three phases and neutral

• Log events like dips, swells andinterruptions

• Trend all measurementsonscreen, with automatic scaling

• Check conformity to EN50160limits or to custom limits

• Capture 40 waveforms showingdetailed dips, swells, interruptions ortransients

• Meet 600 V CAT IV, 1000 VCAT III safety standard required formeasurements at the service entrance

• Transfer stored measurements tothe PC

Flexible connections for currentand potential transformers

Some of these new tools can beconnected directly to low voltage ser-vices, including 120 V/240 V, 480 V,and 600 V. The analyzer can also con-nect in parallels with primary meteringusing PT or CT loops and a set of pre-cision 5 A current clamps. Technicianscan set custom scale factors to displayreadings in primary units. The analyz-ers support all standard power configu-rations:

• Single-phase • Split-phase• Three-phase grounded wye• Three-phase delta• Three-phase high leg delta• Three-phase open leg delta• Single-phase and 3-phase IT


GridContinued from POWER

QUALITYANALYSIS

MADE EASY

better measurement technology and an understanding of therelationship between the cost of building new power plantsand employing energy efficiency programs as a new source ofenergy.

In a recent news release from California’s Flex YourPower, they stated that, properly done, energy efficiency isone/fifth the cost of building new power plants. In a morerecent study implemented for the Northeast Energy EfficiencyPartnership, Inc. (NEEP), investment in energy efficiency was67% cheaper than the avoided cost of electric supply. In otherwords, the cost/benefit analysis of the two approaches to newsources of electricity suggests that energy efficiency programsare 33% the cost of the new power.

Another source of concern for regulators and administra-tors are the externalities (i.e. a cost or benefit that falls on peo-

In spite of advice to the contrary, I have decided to apply a“best practices” analysis to the sacred cow of “free-rider-ship” as it relates to public benefits and utility energy effi-

ciency programs. This analysis is all the more important, because energy

efficiency – with a measurement, verification and sustainabil-ity protocol – is emerging as the single best investment optionfor economic development and emission reduction in suchdiverse economies as the European Union, Canada, China,New England and the far western states of the U.S.

In relationship to public benefits and utility energy effi-ciency programs, one of the most vexing problems surround-ing the issues of free-ridership is definitional. To the econom-ic purist, the textbook definition of free-ridership is as follows:“A free rider is a person who consumes a good without payingfor it.” However, for a variety of reasons, the working defini-

tion of free-ridership asit pertains to public ben-efits and a utility energyefficiency program issignificantly different.In this case, “a free-rider is someone whowould install an energyefficiency measurewithout any programincentives because ofthe return on investmentof the measure, but isable to receive a finan-cial incentive or rebateanyway.”

This definitionhas become the accept-ed language, as used byutilities, program direc-tors and regulatory bod-ies, to discuss energyefficiency programs.It is immediately clear

that these two usages have very little to do with each other. Infact, this is another case of a useful economic concept beingappropriated and re-interpreted for the needs of policy-makers.While it is true that utilities and regulators need a way to dis-tinguish the actual impact of their energy efficiency programson the market, employing the concept of free-ridership to dothis is both confusing and inappropriate.

Then, there is the matter of public and political perception.In a previous era, “energy efficiency programs” were just afancy way of describing a social program or corporate welfare.These prejudices are slowly disappearing, thanks, in part, to


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While it is true that utili-ties and regulators need away to dis-tinguish theactualimpact oftheir energyefficiencyprograms onthe market,employingthe conceptof free-rider-ship to dothis is both confusing andinappropriate.

electricity, especially when demand hasbeen going up 2.2% per year for yearsand the average age of our current fleetof power plants is 39.5 years.

Therefore, the economic and socialvalue of energy efficiency to customersis that it reduces the need for new powerplant construction with its accompany-ing production of new emissions.Therefore, it benefits all customersregardless of their participation in theenergy efficiency program in their homeor business. For these reasons, it shouldbe clear that free-ridership issues forenergy efficiency programs do not ariseout of externality concerns.

So, if energy efficiency programs donot create free-riders from public goodor externality concerns, what is thesource of concern for utilities, regulatorsand/or program administrators? In theearly years of energy efficiency pro-grams, when most programs wereadministered by utilities, their focus wason resource acquisition. In the mid-1990s when market restructuringbecame a major initiative of the utilityindustry, the goal of energy efficiencyoften became “market transformation”.

However, a major component of thisout-dated philosophy was to employenergy efficiency rebates and incentivesto get customers to purchase productsand services which would otherwise beprohibitively expensive for consumers,or did not provide a reasonable rate ofreturn for businesses. These markettransformation programs, in other words,sought to pick winners among energyefficiency products; moreover, they typ-ically focused on large-ticket items, boil-ers, air-conditioning systems, etc., whichhad large up-front costs and limitedreturns.

This approach forced programadministrators to develop a programrationale, which justified this approach.To this end, program administratorsoften created payback standards for effi-ciency funding, which penalized lower-cost projects or projects with over-sizedbenefits. In addition, the standards werebased on the belief that businessesshould implement measures that meet acertain arbitrary payback standard with-out any incentive, and often, the paybackstandards were set too high.

For example, the dividing line forenergy efficiency incentives in Oregon isone year, which means any project witha better return on investment than one

ciency programs that are funded by sys-tem-benefits charges constitute a nega-tive externality for consumers, sincepublic benefits charges are added to allcustomers’ electric bills; and then usedto fund public-purpose energy efficiencyand renewables programs.

Contrary to that argument, thereduction of the electricity demand has aprofound effect on the future of adequatesupplies of electricity and the overallcosts of generating and transmitting

ple who do not participate in the transac-tion), of any public benefits or mandatedutility energy efficiency program. In thiscase, administrators accrue the cost ofissuing the rebate and the benefit of thereduced consumption on the electric sys-tem. Some people argue that energy effi-


KilowattContinued from


year does not qualify for programmonies. On the other hand, Wisconsinhas established a 50% return on invest-ment rule which will not fund projectswith a two year payback.

In the business world, the decision-making process for capital expendituresis much different than some programdirectors think. Energy efficiency pro-jects have to compete with all other cap-ital initiatives, including investments innew production assets or processes,which are usually given first priority.Under this scenario, incentives are oftenrequired for energy efficiency productsand services, even those with significantbenefits, to be chosen by businesses. “Isuspect that time horizons are a majorculprit in sustaining the dichotomy of‘free ridership’ definitions as applied toEE market transformation programs,”stated Christopher Russell, Director ofIndustry Sector for the Alliance to SaveEnergy. “We are all aware of the businesscommunity’s need to earn MORE, andearn it NOW.”

As utilities and states move out ofthe restructuring period and increasinglyturn to energy efficiency as anothersource of new energy, it should beremembered that a resource cannot becounted until it’s purchased and installedby a consumer. By writing a purchaseorder and a cheque, no customer is get-ting anything for free. According to JonWellinghoff, longtime energy efficiencyadvocate, “Energy Efficiency is viewedby both utilities and regulatory commis-sions very differently than supply sidemeasures. And it shouldn’t be. Utilitiesshould be required to acquire demandside measures in the same manner asthey acquire those on the supply side ifthe demand measures can be provided as‘utility grade’ (i.e. reliable and pre-dictable and persistent) for a specifiedperiod of time.”

The Minnesota Public ServiceCommission has adopted a very saneapproach to the free-rider issue. Theyassume that “free drivers” – people orcompanies that install the energy effi-ciency measure as a result of the indirecteffects of the energy efficiency programbut never collect a rebate or incentive –offset each other.

Ultimately, the whole free-riderissue hinges on the fact that it is notori-

ously difficult to measure. Does anyone actually think that

General Motors or Ford spent much timeworrying about the “free-riders” of theirEmployee Discount Sale this summeronce they decided to offer it? It was justa part of increasing overall auto sales.

Finally, the best measurement of theprogram’s effectiveness, other thanmoney spent, is the total of electricitysaved. In the 21st Century, we have thetechnology and the available energy effi-

ciency expertise to stem the growth ofelectricity consumption and the need fornew power plants.

We cannot allow the inappropriateuse of the concept of free-ridership toimpede the progress of thoughtfuldeployment of energy efficiencythroughout the U.S. After all, every kilo-watt saved is another kilowatt availablefor economic development with all ofthe benefits of cost savings and emissionreductions.


KilowattContinued from

When Manitoba Hydro neededto improve and expand com-munications and information

sharing for its 5,500 employees, its cus-tomers and its business partners, itturned to a collaborative software toaddress their needs.

Already familiar with SAP systemtechnology in 1992 and ‘93, Dan Lohr,Manager of Integrated Systems atManitoba Hydro, decided to move aheadwith mySAP Business Suite technology.

“We had home-developed systemsfrom 25 years ago,” says Mr. Lohr, “andfrom the finan-cial side(accounting andmaterials man-agement), SAPmet our require-ments.”

The need forgreater account-ability was also adriving force toincorporate thenew technologyat ManitobaHydro.

“By 2003there was at r e m e n d o u samount of pres-sure to have bet-ter managementreporting,” saysMr. Lohr. “Welooked at every-one and choseSAP.”

“NetWeaver is the technology onwhich it rests,” points our MarkMandzik, Executive Assistant to the VicePresident of Corporate Relations atManitoba Hydro.

“We did evaluations of the differentsystems that are out there, and theBusiness Warehouse of NetWeaver hadgreat integration application.

“We can interface with the othersystems and manage the traffic.”

According to the literature, the tech-nology that is mySAP Business Suiteprovides complete integration, industry-specific functionality, unlimited scalabil-ity, and easy collaboration over theInternet .

In the case of Manitoba Hydro(Canada’s fourth largest utility), by stan-dardizing its integrated system, the utili-ty eliminated disconnects between itssystems and its people, helping toachieve the company’s goal of maximiz-

ing revenues fromexport power salesand in turn maintain-ing its low rates forits customers. In addition, the SAPEnterprise ResourcePlanning softwareprovides diverseopportunities toaccountants in areassuch as CorporateAccounting, Capitaland OperatingBudgeting, FinancialPlanning andRegulatory Affairs,and Internal Audit.A comprehensiveintegration andapplication platform,SAP NetWeaverworks with the exist-ing IT infrastructureto enable and man-

age change. With SAP NetWeaver, youcan flexibly and rapidly design, build,implement, and execute new businessstrategies and processes. You can alsocombine existing systems while main-taining a sustainable cost structure.

“From an HR (human resources)point of view, there are a lot of benefits,

Electricity Today Issue 7, 2005

MANITOBA HYDRO EXPANDSCOMMUNICATIONS,

INFORMATION SHARINGWITH EMPLOYEES

By Don Horne

“The work flow is that

much smoother.

“When we get requests

for training courses and

forums, a request can go

automatically to the supervi-

sor for approval. No paper

means much faster.”


as we were able to create a two-way system between managerand employee,” says Rob Lanyon, System DevelopmentSupervisor with Manitoba Hydro. “When we went live (withthe HR and R3 systems) in June of 2003, we had employee paystub info all online. The information was right at their finger-tips; and no more paper.”

In addition, the human resources department at the utilityis faced with the challenge of replacing an aging workforce

with fresh faces. Thenew technology makes itthat much easier.

“We can post (newjobs and job openings)both internally andexternally through thenew system,” says Mr.Lohr.

The new technology isalso that much moreuser-friendly, which isnecessary for someworkers who aren’t thatcomfortable with com-puter technology.

“The older system wastoo complex for somepeople,” says Mr. Lohr.“We have a strong, loyalolder workforce here,and there’s been a lot ofchange recently. Therewas some resistance ini-tially, but they are find-ing that this new systemworks well.”Mr. Lanyon adds thatreplacing the archaicpaper trail with an inter-active computer systemallows for faster, moreresponsive employer/

employee communication.“The work flow is that much smoother,” he says. “When

we get requests for training courses and forums, a request cango automatically to the supervisor for approval. No papermeans much faster.”

SAP NetWeaver embraces Internet standards such asHTTP, XML, and Web services. Ensuring openness and inter-operability with Microsoft .NET and Java 2 PlatformEnterprise Edition (J2EE) environments such as IBMWebSphere.

SAP NetWeaver is the technical foundation of mySAPBusiness Suite solutions, SAP xApps composite applications,partner solutions, and customer custom-built applications. Italso enables Enterprise Services Architecture, SAP’s blueprintfor service-oriented business solutions.

Electricity Today Issue 9, 2005

LaPrairie has been providing theelectrical industry with SadtemInstrument Transfomers formore than 15 years. Sadtem IT’s are designed usingDry Type Insulation, thereforeallowing us to offer compact,lightweight designs.We offer a comprehensive lineof 5-46kV Primary MeteringUnits that comply to CSA orANSI standard. Whether your requirement isfor a Pole Mount, Padmount orVault Mount application, wehave the assembly for you.For any of your PrimaryMetering requirements,LaPrairie is your answer!

“Primar“Primary Meteringy MeteringAt Its Best”At Its Best”

ManitobaContinued from

Artist’s rendition of Manitoba Hydro’snew headquarters.

The restructuring of the Texas elec-tricity market brought with itvisions of sweeping change in

how customers purchase and consumeenergy. Competition among providerswas seen as the way to bring lowerprices and new products and services tocustomers, and new levels of efficiencyto the operations of the electrical grid.

Following the recent launch of thenew market, competition is clearly bene-fiting many customers. But crucial partsof the restructuring vision are on hold asmarket participants continue to struggleto meet the challenges of executing inthe new environment. Many of thepromising new products and servicesenvisioned during the restructuring

debate have been slow to develop, espe-cially for smaller customers.

Meanwhile, global advancements intechnology have given rise to a numberof exciting new “Smart Energy” innova-tions that can transform the way cus-tomers use energy: enabling efficiency,adding convenience, and managingusage to take advantage of lower, off-peak energy prices. For residential andsmall commercial customers in Texas,however, these products and servicesstill face a number of barriers — thelargest and most important of which isthe absence of detailed meter data.

More granular meter data canempower customers to save money, helpthe restructured electricity market to

function, and promote energy efficiency.By measuring consumption over inter-vals or time blocks, advanced meters canprovide customers with detailed views oftheir energy usage, enabling electricityproviders to offer pricing plans thatreflect the changing costs of energy, andbringing the proven value of demandelasticity to the new market.

Wholesale electricity prices spikewhen supply struggles to meet surges indemand. At these times, inefficient“peaking plants” are fired up, and trans-mission lines become congested.

This drives up costs and puts thesystem at risk for brownouts and black-outs. The overall cost of electricity alsospikes when the transmission and distri-bution system (the grid) becomes over-loaded, forcing operators to purchasemore expensive power to relieve conges-tion. Empowering customers to reducetheir demand during these peaks candecrease overall wholesale prices andimprove system reliability.

Today, the vast majority of Texascustomers — all but the largest industri-als — are still served by traditionalelectromechanical meters, which deliversingle monthly kilowatt-hour readingswhen directly observed. These cus-tomers therefore must be served by aver-age kilowatt pricing. Advanced meterdata would expand the competitive play-ing field for retail electric providers inthe restructured market, allowing themto offer rate plans tailored to customers’lifestyles and their ability to respond toprice signals. This can help insure thelong-term success of the market, byrewarding creative providers and reduc-ing the inherent advantages of size andincumbency.

Advanced meters create marketincentives for targeted energy efficiencytechnologies and services, and thus are asource of clean energy and a solution forheavily congested transmission areas.Demand reductions prompted by a more


SMART METERS

THE CASE FOR ADVANCED ELECTRICITYMETERING IN TEXAS - PART 1


granular knowledge of consumption pat-terns, in combination with price signals,provide new capacity to the system withzero emissions of air pollutants byencouraging investment in new, smartenergy technology, as well as cost effec-tive behavioral changes. And customerswith the incentives and tools to reducepeak use almost invariably reduce theiroverall consumption as well.

Meters have traditionally beenowned, installed, maintained, and read bythe regulated utilities. When the TexasLegislature restructured the electricityindustry with Senate Bill 7 in 1999, itincluded a provision stating that “meter-ing services… shall be provided on acompetitive basis,” beginning in 2004with commercial and industrial cus-tomers.

Competitive metering was viewed asa means to create a market for upgradesin metering services, which in turn wouldenhance competition by increasing theavailability of detailed consumption data.At the time, competitive metering was afledgling concept that had not yet beenimplemented fully in any other state.Since then, in every state where it hasbeen tried, competitive metering hasfailed to result in meter upgrades for allbut the most sophisticated commercialand industrial customers.

In order to comply with the law’sJanuary 1, 2004 deadline, the PublicUtility Commission of Texas (PUCT)approved a rule allowing commercial andindustrial customers, or a Retail ElectricProvider (REP) or third party authorized

by the customer, to own their meters. Nocustomers had formally applied for com-petitive meter ownership during the firstthree months of eligibility.

These experiences, in addition to theinformation discussed in this paper,strongly suggest that in order to achievethe legislative intent, metering servicesshould remain a utility function at leastfor smaller customers.

This document is intended to assistpolicymakers, marketparticipants, and inter-ested parties in consid-ering both the value ofmass market demandparticipation and howto stimulate deploy-ment of advancedmeters as the enablinginfrastructure.

THERESTRUCTURED TEXASELECTRICITY MARKET

Electricity deregu-lation nationally hasproduced unevenresults, with somenotable negative experiences providingheadlines and coloring the national per-spective on the issue. In this environ-ment, proponents’ eyes remain fixed onTexas, which opened its market to retailcompetition on January 1, 2002. There ismuch to praise about the Texas model, asvirtually all customers in the restructuredareas of the state now have a choice ofproviders and are paying less for theirelectricity than they did before.

Observers frequently attributeTexas’s success, in part, to the surplus ofavailable electricity.

Unlike California, which deregulat-

ed its market when supplies were partic-ularly vulnerable, Texas is awash in gen-eration capacity, much of it from plantsconstructed in the past few years.Combining this with the relatively lownatural gas prices that existed at that timehas helped to keep both wholesale andretail prices down during the startup ofcompetition.

The Texas market has attractednumerous competitive Retail Electric

Providers (REPs), and apromising percentage ofthe overall supply is nowbeing purchased fromnon-incumbent suppliers.While this is inarguably asign of success, much ofthe competition to datehas been concentrated inthe mid- to large commer-cial customer categories.For the majority of cus-tomers, the successes ofrestructuring have beenless evident:• Fewer than 12 percent ofresidential customers inany eligible utility service

area switched from their incumbents dur-ing the first two years of competition,and a long-term growth trend in providerswitching has yet to emerge. CompetitiveREP market share has actually decreasedin some months.

• The difference has narrowed dra-matically between competitive REPs’residential rate offerings and the ratesrequired to be charged by REPs affiliatedwith the former vertical utilities (knownas the Price to Beat).

• The low-price leader for residential


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TexasContinued from

A strategic and practical approach to smart metering

CAN DASMART METERING

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A C A D E M YMETERING INTERNATIONAL

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Workshop • Conference • Field visits

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· Assess the role smart meters can play in delivering

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· Gain experience and knowledge to efficiently

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· Hear about the latest trends in smart metering

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The Government of Ontario aims to have 800,000 smart electricity meters installed in homes by 2007 and in all homes by 2010.

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Program highlights:

! Preconference seminar: Prepayment metering:

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and small commercial customers, NewPower Company, declared bankruptcy in2002 and exited the Texas market.

• A detailed analysis in2002 cast doubt on the abil-ity of competitive REPs tomake a profit selling tosmaller customers under thePrice-to-Beat structure, rais-ing concerns about the mar-ket’s long-term ability toensure a strong level ofcompetitive choice for theseconsumers. The majority ofREPs in the market are lim-iting their offerings to com-mercial & industrial cus-tomers.

• The Price to Beat is scheduled to bephased out in 2007, after five years, atwhich time competitive REPs will be

forced to compete head to head with theincumbents.

In the absence of advanced meters,that playing field would be limited toflat-rate price offerings, under which theadvantages of incumbency and existingmarket share could become even more

pronounced.Other problems lurk beneath the sur-

face. While there is unanimous consentthat the market launched at a fortuitous

time, evidence is emerging that the sur-plus of supply has not stopped aggressivetraders from manipulating the market towin artificially higher prices.

The market price of natural gas, thedominant fuel source for marginal Texaselectricity generation, has risen signifi-

cantly in recent years.At the same time, poli-cymakers concede thattheir ability to regulatereserve power marginshas been significantlyreduced. Only time willtell how the restruc-tured market willrespond to spikes inpeak demand duringthe inevitable boom-bust cycles of genera-tion construction to

come.Look for Part 2 of “The Case forAdvanced Electricity Metering in Texas”in the next issue of Electricity Today.

ADVERTISERS INDEX - Issue 9, 2005

ADVERTISER PAGE CONTACT INFO ELECTRICITYFORUM WEB PAGEArga Controls 30 www.argacontrols.com www.electricityforum.com/products/arga.htmBell 9 www.businessonthego.ca/utilitiesComverge Inc. 5 www.comverge.comCUEE 41 www.cuee.comEDIST 40 www.edist.caElectric West 43 www.electricwest.comEnercom 44 www.enercom.toFlex-Core 45 www.flex-core.com www.electricityforum.com/products/flex.htmFLIR Systems Ltd. 31, 45, 48 www.flir.com www.electricityforum.com/products/flir.htmGT Wood Company Ltd. 45 www.gtwood.com www.electricityforum.com/products/gtwood.htmHubbell Power Systems 2,27,45 [email protected] www.electricityforum.com/products/hubbell.htmHunt Technologies 15 www.hunttechnologies.com www.electricityforum.com/products/hunt.htmIntellimeter 22 www.intellimeter.on.caInterfax Systems Inc. 21 www.interfaxsystems.comKinectrics 19 www.kinectrics.comLaPrairie Inc. 35 www.laprairieinc.com www.electricityforum.com/products/laprairie.htmLineal 29 www.lineal.com Lizco Sales 45 www.lizcosales.com www.electricityforum.com/products/lizco.htmMagna Electric 24, 25 www.magnaelectric.com www.electricityforum.com/products/magna.htmManitoba HVDC 32 www.hvdc.ca www.electricityforum.com/products/manitobahvdc.htmMidas Metering Services 26 www.midasmetering.comMorgan Schaffer 28 www.morganschaffer.com www.electricityforum.com/products/morgan.htmNETA 39 htttp://neta.lps.org/CONF.htmlNynas 17 www.nynas.comOlameter Inc. 13 www.olameter.comPirelli 7 www.pirelli.com www.electricityforum.com/products/pirelli_llc.htmSmart Metering 38 www.spintelligent-events.com/canada2006/en/Stratos 11 www.stratosglobal.comSynergy Energy Inc. 33, 45 www.synergyenergyinc.com www.electricityforum.com/products/SYNERGY_ENERGY_Inc.htmlTantalus Systems Corp. 47 www.tantalus.comTechniCAL Systems 2002 37 www.technical-sys.com www.electricityforum.com/products/technical_systems2002.htmThe VON Corporation 34 www.voncorp.com www.electricityforum.com/products/von.htmWire Services 36 www.wireservices.ca www.electricityforum.com/products/wire_services.htm

TexasContinued from Page 37

While there is unanimous consent that the market launchedat a fortuitous time, evidence is emerging that the surplus ofsupply has not stopped aggressive traders from manipulatingthe market to win artificially higher prices.

http://www.electricityforum.com/t&d/company.htm
















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