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January 2006 Volume 18, No. 1

PUBLICATION MAIL AGREEMENT # 40051146

Electrical Buyer’s Guides,Forums, On-Line Magazines,Industry News, Job Postings,Electrical Store, Industry Links

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January 2006 Volume 18, No. 1

Integrated AM/FM and GIS foran electric distribution systemIntegrated AM/FM and GIS foran electric distribution system

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3

6 Standing At The Crossroads Of New Generation

8 Integrated AM/FM and GIS for an Electric Distribution System16 IESO Issues Assessment of the Reliability of the Ontario Electricity System

12 SCADA Deployment Using Object Linking and Embedding Process Control37 Security In Automated T&D Systems, Authorization, Authentication,

Integrity And Confidentiality

14 Free All Wisconsin Utilities to Make Money Helping Customers Save Energy

20 IPPSA 12th Annual Conference & Trade Show March 12-14, 200643 7th Annual ENERCOM Conference Looks At The Future Of Transmission,

Distribution And Generation

22 Tomorrow Fund Offers A Helping Hand To Stressed-Out Utilities

24 Examples Of Premature Stator Winding Failure In Recently Manufacutred Motors And Generators

28 Ontario’s Electricity Distributors New Legislation And The SmartImplementation Of Smart Meters

30 The Case For Advanced Electricity Metering In Texas - Part II

45

46

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18, N

o. 1

Ja

nuar

y 20

06

in this issueEDITORIAL

GENERATION

VIEWPOINT

SMART METERING

TRANSMISSION & DISTRIBUTION

SCADA

ADVERTISERS INDEX

CONFERENCES

RESEARCH & DEVELOPMENT

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.

Canada Post - Canadian Publications Mail Product SalesAgreement 40051146 ISSN 0843-7343Printed in Canada. All rights reserved. The contents of this publication may not be reproducedin whole or in part without prior permission from thepublisher.

Member of:

Publisher/Executive EditorRandolph W. Hurstrandy@electricityforum.com

Associate Publisher/Advertising SalesCarol Gardnercarol@electricityforum.com

EditorDon Hornedon@electricityforum.com

Web Site Advertising SalesBarbara Johnforum@capital.net

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Production ManagerAlla Krutousalla@electricityforum.com

Visit our Web Site:www.electricityforum.comE-mail: hq@electricityforum.com

Subscribe on-line:www.electricityforum.com/et/subscribe.htm

PRODUCTS AND SERVICES SHOWCASE

ET_1_06(Jan) 1/30/06 3:55 PM Page 3

Electricity Today4

editorial board

BRUCE CAMPBELL

BOB FESMIRE

CHARLIE MACALUSO

SCOTT ROUSE

BRUCE CAMPBELL, LL.B., Independent Electricity System Operator (IESO)Mr. Campbell holds the position of Vice-President, Corporate Rela-

tions & Market Development. In that capacity he is responsible for the evo-lution of the IESO-administered markets; regulatory affairs; external rela-tions and communications; and stakeholder engagement. He has extensivebackground within the electricity industry, having acted as legal counsel inplanning, facility approval and rate proceedings throughout his 26-yearcareer in private practice. He joined the IESO in June 2000 and is a mem-ber of the Executive Committee of the Northeast Power CoordinatingCouncil. He has contributed as a member of several Boards, and wasVice-Chair of the Interim Waste Authority Ltd. He is a graduate of the Uni-versity of Waterloo and Osgoode Hall Law School.

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

nologies division. He writes regularly on a range of power industry top-ics 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 is Pres-ident-Elect of the IEEE Power Engineering Society (PES), Immediate PastChair of the IEEE PES Substations Committee, and an IEEE Fellow.

DAVID W. MONCUR

JOHN McDONALD

ET_1_06(Jan) 1/30/06 3:55 PM Page 4

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Electricity Today6

Ahot, dry summer and frostywinter have placed anincreased demand on the

grid. The hot and dry factor in the sum-mer was a double-edged sword, as theincrease in demand for air conditioning(compounded by lowered water levels forhydro-electric suppliers) ultimatelyresulted in higher costs for the consumer.

Add to the mix the dramatic increasein natural gas and oil prices.

Natural gas prices jumped 9 percent, rising by $1.29 (U.S.) to $14.99 perthousand cubic feet on the New YorkMercantile Exchange on December 8 -the biggest fluctuation of any commodityin the world that day. The January natur-al gas futures topped the previous recordclose, $14.34, which was set on Oct. 25.

But these are not the only pressuresbeing brought to bear on the industry.

On the west coast, the SnohomishCounty Public Utility District (PUD)abandoned a bid to lower customerpower rates by 4 per cent for this yearfollowing a federal lawsuit requestingmore water for endangered Chinooksalmon on the Columbia and Snakerivers.

The water is needed to aid down-stream migrating juvenile salmon, saysthe National Wildlife Federation (NWF).And their pleas are not just words in thewind, as they won a similar lawsuit earli-er in the year for the summer migration.

According to the Bonneville PowerAdministration (BPA), which produceselectricity at the dams, such water losseswill cost the region 770 averagemegawatts of energy - enough electricityto power almost all of Seattle for a year.

In hard dollars, that's to $450 millionannually in revenue losses, $347 millionof which would be passed on to Bon-neville's customers. Now, instead of arate reduction for 2006, PUD customersare looking at an increase.

Tacoma Power faces a potentialincrease of $17 million in its costs nextyear; Seattle City Light, which reducedrates earlier this year, also could facehigher costs.

The NWF say that Bonneville has"cried wolf" in the past over water-flowrequests, pointing to the recent increase

in revenues and a one per cent drop inrates.

But environmental concerns do notstop at minimum water levels.

Advocates of wind power must beaccommodating to avian concerns (birdsand bats, etc.), being careful not to placethese giant wind-generation units nearestablished flight paths and nesting andconservation areas.

With prices for oil and gas risingsharply in recent years, activists in theU.S. and Canada have been campaigningfor more financial assistance to help low-income people pay energy bills.

In recent months, the Canadian gov-ernment unveiled a plan to pay a total of$565 million (Cdn) to low-income fami-lies with children and to senior citizens.

In the U.S., advocates for low-income people have argued that $5.1 bil-lion (US) in federal energy help is need-ed this winter. And that isn't even consid-ering the havoc wrought by hurricanesRita and Katrina.

In Ontario, the Ontario PowerAuthority (OPA) has recommended thatthe province needs to construct a dozenor more nuclear reactors that wouldreplace or refurbish reactors at a cost of$30 or 40 billion. Opponents in Ontarioto more nuclear construction point torenewable options like geothermal andbiomass generation - the latter drawingcriticism from the OPA as being unviableas it is wrong to grow crops specificallyfor electricity production.

Once the bad boy of electricity gen-eration, it seems coal may be back infashion.

Nevada Power is considering cheap-er coal as an alternative fuel for generat-ing power, but the mere suggestion ofbuilding conventional coal-fired plantsstirs controversy.

Environmentalists consider tradi-tional coal-fired plants to be the pollu-tion-spewing dinosaurs of the energyindustry. But officials from NevadaPower's parent say technology may helpallay those same environmentalists' fears.

The senior vice president of SierraPacific Resources Roberto Denis hasstated that they are "actively pursuingand will pursue building clean, efficientcoal power plants".

In this case, clean means coal-firedpower plants constructed with the latestin pollutant-stripping technologies (butnot integrated gasification combined-cycle projects that convert coal into gas,as they are not commercially viable).

At prices quoted in late December2005, it cost $2 in coal to generate thesame amount of electricity that wouldrequire $12 in gas (based on an averagefor the Southern California border onDec. 21).

Ironically, by 2010 or 2012 whenNevada is expected to be building a coal-fired plant, such gasification technologywill be ready for widespread use.

Previous studies have shown inte-grated gasification plants to be 25 per-cent more expensive on a kilowatt hourbasis than conventional pulverized-coalplants, but a recent study from GE Ener-gy reveals that the price premium can bereduced to 10 percent.

Another consideration is that thefederal government may follow Califor-nia's lead in restricting use of power fromconventional coal-fired power plants.

The California Energy Commissionproposed that investor-owned electricutilities in that state be prohibited fromentering long-term contracts for powerfrom plants that create more carbon diox-ide than natural gas-fired plants.

The net result of all this is simple:more generation is needed now, but aconsensus on how that will be achievedseems unattainable.

Perhaps the best answer is to pushforward with every option, now, so thateach can either thrive or wither when putto the test. Certainly the worst option isto do nothing - and that would usher in amodern day dark age.

EDITORIAL

STANDING AT THE CROSSROADS OF NEW GENERATION

By Don Horne, Editor

ET_1_06(Jan) 1/30/06 3:55 PM Page 6

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Electricity Today8

The Choctawatchee ElectricCooperative (Chelco) recentlycompleted digitizing their

original paper maps using AutoCAD.This project was completed in house andencompassed 322 drawings at 1:500 andsome 1:200 scales.

Chelco is located in the panhandle ofFlorida and serves 30,000 customers inan 1,800 square mile area. Alabama is onour northern border and the Gulf of Mex-ico is on the south.

Chelco immediately realized thebenefits of electronic maps.By using layers, Chelcocould add more informationthan what was on crowdedpaper maps. With electronicmaps they could add multi-ple layers for any map fea-ture such as roads or jointuse poles. These layerscould be assigned differentcolors to make them morevisible. They could also turnlayers on and off and seeonly the map details thatwere needed. They couldeasily create copies of themaps and make them avail-able over the internal computer network.

On the old paper system when anarea became too populated Chelco wouldcreate a new paper map using a smallerscale. With digitized maps it was unnec-essary because they could zoom in andout of a map at any scale.

There are many advantages usingelectronic maps over paper maps. Chelcosoon discovered they needed more thanjust electronic maps. They wanted a toolthat could provide them with a system-wide seamless map. Chelco wanted toquery the billing data and have the mapszoom into a given location. They wantedto be able to draw a map that could showequipment scheduled for maintenance.And they wanted the ability to trace ourcircuits and let the maps tell them howmany customers a circuit serves. Chelcowanted a true GIS.

THE SEARCHChelco evaluated applications work-

ing with AutoCAD that tried to combinethe individual map files into an integrat-ed GIS. Chelco found the available soft-ware products could only do one or twoof the tasks and performance was farfrom acceptable.

They were introduced to Environ-mental System Research Institute’s(ESRI’s) ArcInfo and ArcView in a fewyears ago. It seemed to be the perfectsolution to take Chelco beyond electron-ic maps into the world of GIS. Coveragescould be created and maintained inArcInfo and then viewed by users withArcView. Instead of individual maps,ArcInfo and ArcView treated our data asone seamless map. Chelco began search-ing for a third party application designed

to work with an electric dis-tribution utility. They weredisappointed when Chelcofound nothing on the marketto fit their needs.

In the spring of 1996 Chel-co saw an article in a trademagazine about the veryproduct they needed. Thearticle claimed UtilityAutomation 2000 (UA2000)had successfully integratedworkorder creation and post-ing, truck maps, billing data,and trouble call. Chelcoimmediately made arrange-

ments for a demonstration. At the first demonstration of soft-

ware developed by UA2000 Chelco knewtheir search was over. The demonstrationwas given using an electric distributioncooperative with 38,000 accounts. Itcould display the entire electric distribu-tion system as a complete seamless mapfaster than AutoCAD could draw evenone of our individual digitized papermaps.

UA2000 had a product working withESRI’s ArcInfo and ArcView that couldcreate and post work orders and fieldinventories using a Windows based lap-top. A laptop could also be used to dis-play truck maps. It interfaced with Chel-co’s billing software allowing dailyupdates of any changes to the maps or tothe billing data. It could interface withany SCADA system they might establish.It provided a trouble call application withautomated phone answering. It had aneasy-to-use interface to replace the papertruck maps for use in the field. It met andexceeded all of the search criteria andperformance specifications.

ROLLING UP OUR SLEEVESBy the summer of 1996 Chelco

entered into an agreement with UA2000to convert their existing electronic mapsinto ArcInfo coverage’s and provide them

TRANSMISSION & DISTRIBUTION

INTEGRATED AM/FM AND GIS FORAN ELECTRIC DISTRIBUTION SYSTEM

By Tommie Gipson, Chelco Services Inc.

continued on page 10

Integrated software places information at the fingertipsof those working in the field.

ET_1_06(Jan) 1/30/06 4:19 PM Page 8

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Electricity Today10

with all of the software tools needed torealize true GIS capabilities. They pro-vided UA2000 with a sample of theirbilling data and all of the electronic mapsfrom AutoCAD. After sending the mapsto UA2000 Chelco kept paper copies ofall new work orders to be posted to thenew ArcInfo system once they receiveddelivery from UA2000.

Chelco brought the new system online in the fall of 1997. ArcInfo is thecore of the system. Each night it runs anovernight process that has proven to bestable and efficient. In the overnightprocess ArcInfo gets any as built workorders from engineering and automatical-ly posts them to the system. It gets thelatest billing data from their billing soft-ware and updates both the maps and theautomated phone answering system fortrouble call. It runs an integrity check onall of the data and generates an error logeach night. The error log is checked thenext day by the mapping department tomake any necessary corrections such asbilling data that has no correspondingmap data. The mapping department canalso visually see any line sections thatmay have been accidentally opened froma source feed and corrects the problem.Each night the overnight process thentransfers all of the updated informationback to our Local Area Network (LAN).

The Mapping and Dispatch Depart-ments were the first to begin using thenew software. Chelco’s mapping depart-ment began the labor-intensive task ofposting all of the work orders held duringthe conversion process. New subdivi-sions and work plans were also posted tothe new system. Our dispatchers weregiven training in the new system andquickly began realizing the benefits ofkeying in an account and not only seeingwhere the account is located, but also theability to zoom out and see the substationfeeding the account. All of the billingdata is available with one mouse click onthe map. And there were no longerrestrictions from the old map boundaries.

Next the engineering personnel weregiven laptop computers. The laptopswere Pentium 166 with 16 Megs of ram.ArcView was loaded along withUA2000’s application with new softwaretools to make their jobs faster and moreefficient. The staking engineers weregiven training on the new system andencouraged to create test work orders.

Chelco’s plant inventory can now bemaintained with each new work ordergenerated. As built jobs are now postedto the maps each night and available tothe rest of the company the next day.Engineers can access demand and usageinformation on an account from their lap-tops while in the field.

The engineering department can

now generate special maps to help indesign and planning. One of the first pro-jects was a cable-aging map for under-ground cable. Underground cable iscolor-coded based on age to help sched-ule replacement. Maps of only threephase lines can be drawn to look forpotential tie lines. Maps of conductors ortransformers meeting certain criteria cannow be generated in seconds. We nolonger have to maintain two set of maps(planning and detail maps). Because ourmaps are true seamless maps (the olddetail map boundaries no longer exist)any project can be viewed in its entiretyand printed or plotted.

When Chelco issued laptops to ouroperation department we increased theram to 32 Megs. They offered voluntarytraining and had 100 percent attendanceduring the first two months of training.There were mixed reactions to the newmaps in the beginning. After training andusing this new tool most of operationswere happy with the change. It was easyto see how much the new computer mapswould help them in their jobs. On the oldpaper maps a dense area could take sev-eral minutes to locate the account need-ed. Now any account is located andshown as soon as it is keyed in the com-puter.

The old paper truck maps might goas long as two years before being updat-ed. Now the maps can be updated dailyby logging on to the LAN and transfer-ring the latest version of the maps com-

plete with billing data. Tracing can bedone on the laptops both upstream anddownstream. Upstream tracing can beused to show the source feed at any pointon the system. Downstream tracing willshow all of the consumers fed beyond theselected point along with the total con-nected kva and the number of transform-ers. The longest circuit takes 10 to 15seconds to trace and the smaller circuitsare almost instantaneous.

The marketing department can nowcreate maps of the entire system fromselect queries such as kwh greater than acertain value. They can quickly generatea map showing all of our demandaccounts color-coded by size. On of thefirst maps generated was a system-widemap of all 30,000 customers to visuallysee density patterns on the system. Thesystem can generate any of these maps inseconds and then plot them.

CONCLUSIONChelco have successfully integrated

AM/FM with GIS. The maps are dynam-ic and the entire company is able to takeadvantage of the most recent map andbilling data. The truck map software iseasy to use and fast. The combined sizeof all of our old AutoCAD drawings was920 megabytes. The same data takes upless than 90 megabytes in ArcInfo andArcView. When zipped the size is 40megabytes for use in data transfers fromthe LAN.

Trouble calls are handled more effi-ciently by both dispatch and operations.Knowledge about our system that waspreviously unavailable can be readilyaccessed. We now have the ability tobring GPS and SCADA data to our mapswhen it is decided to implement them.Creating, processing, and posting workorders has brought the potential torethink the way business is done bystreamlining and becoming more effi-cient.

ESRI has made ArcExplorer avail-able from their web site and some ofChelco’s employees use this software forviewing the system map. Every employ-ee now has access to our GIS. They areconsidering publishing some of the dataover the Internet to be viewed with Arc-Explorer. The potential for new ways ofusing our valuable data is now unlimitedbecause of our integrated GIS.

The new integrated GIS has impact-ed every department in a positive way.They have found the “Holy Grail” of GISfor an electric distribution system.

GIScontinued from page 8

5

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Electricity Today12

SCADA deployment can effec-tively use OPC (or OLE, objectlinking and embedding process

control) provided that the driver’sSCADA engine properly handles theunique SCADA communication require-ments. Traditionally, SCADA (Supervi-sory Control and Data Acquisition)deployment has always used proprietarysoftware applications and drivers toenable control centers to effectively man-age the large amount of data collected.With the introduction of OPC, there havebeen various attempts at applying indus-trial standards to these SCADA basedimplementations. To help these attemptssucceed and avoid significant cost over-runs, integrators must differentiatebetween “plant-based” OPC mentalityand SCADA applications.

SCADA IS DIFFERENT FROMMANUFACTURING

Manufacturing plants are typicallyconfined to a small geographical area,and are usually less than a square mile.This includes businesses such as Pulp &Paper, Petrochemicals, Refineries, Auto-motive, etc. Their communication meth-ods normally use reliable Ethernet or ser-ial mediums, and frequently use a DCS(Data Control System) and/or PLCs (Pro-grammable Logic Controllers) to controltheir process. In sharp contrast, SCADAapplications cover very large geographi-cal regions, frequently measured in thehundreds or thousands of square miles.These enterprises include: pipelines, oilgathering fields, electrical transmissionutilities, water/wastewater, etc. As aresult, they usually prefer satellite, radio,or modem communication, and typicallyrely on RTUs for their control. From adriver perspective, the biggest differencebetween Plant and SCADA implementa-tions is the communication. (Whilehybrid plants exist, we only cover thepure SCADA concepts, which can thenbe easily transferred to hybrid plants.)

Due to their confined geographical

nature, Manufacturing Plants typicallyuse a robust and reliable Ethernet back-bone, which are usually installed in elec-trically quiet (i.e. little noise) locations.Bandwidth, from 9600 bps to Gigabitnetworks, is plentiful. They are also ableto use a relatively small number of PLCsand DCSs, as the wires can economicallyreach all the necessary equipment, sen-sors, actuators, etc. On the other hand,due to their large coverage area, SCADAenterprises rely on noisy telemetry (wire-less) or telephone (leased) line communi-cation. Consequently,they also use lower com-munication speeds (300 –9600 bps), and a verylarge number of RTUs,frequently numbering inthe hundreds or eventhousands.

OPC Servers forSCADA applicationsmust take these factorsinto account. They mustoptimize their communi-cation to allow for extranoise, low bandwidth and a large devicecount. They must also handle their prior-ity of operations differently than in aplant. Finally, the SCADA Master (theOPC Client application) must behaveslightly differently to help the OPC serv-er behave properly.

NOISY COMMUNICATIONNoisy communication is the hall-

mark of SCADA operations. Invalidpackets are very common, and extra bitsoften slip into the packets due to radiosquelch. It is important for SCADAservers to differentiate between aninvalid data packet as indicated by a badCRC (Cyclic Redundancy Check), andpackets that are invalid due to radiosquelch. In the former, the read must beperformed again. But, if the SCADAserver recognizes the latter (extra bitsafter a good CRC is detected), it can eas-ily clean up the data by simply ignoring

the extra bits. This data cleansing enablesthe SCADA server to avoid extra readswhere they are not required, and save onprecious bandwidth. OPC enables theservers to have a dynamically config-urable number of retries. Users can spec-ify the number of retries that are accept-able in their specific situations.

LARGE RTU COUNTA large number of RTUs (Radio

Transmission Units) is also a signatureaspect of SCADA applications. While

plant-based driversrarely connect to morethan a few PLCs simul-taneously, SCADAservers frequently con-nect to tens or even hun-dreds or RTUs. SCADAservers must usuallyshare a single connec-tion amongst manyRTUs, resulting in aconnect-read-discon-nect operation. SCADAserver must be very effi-

cient in their connection and disconnec-tion procedures. As well, they mustadhere to a dynamic polling sequencethat enables them to read data from allthe devices in a round-robin pollingsequence, and also be able to interruptthe sequence with a higher priority writeoperation. Once the interruption is com-plete, the SCADA server must resume itsregularly scheduled polling sequence.OPC uses a timestamp to indicate the lasttime that a given value was read. Thisenables users to easily tell if they shouldinterrupt the polling sequence to refreshtheir data, or if their data is at an accept-able age. This reduces the number ofinterruptions to the SCADA server, andreduces system load.

LOW BANDWIDTHLow Bandwidth communication

continued on page 15

SOLUTIONS

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SCADA

SCADA DEPLOYMENT USING OBJECT LINKINGAND EMBEDDING PROCESS CONTROL

By Randy Kondor, Matrikon

Low Bandwidthcommunicationplagues SCADAoperations. Unlikein Plants, SCADAbandwidth is at apremium.

ET_1_06(Jan) 1/30/06 4:20 PM Page 12

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ET_1_06(Jan) 1/30/06 4:20 PM Page 13

Electricity Today14

Why does Wisconsin continue to reward electricalconsumption, generation and marginally com-petitive solutions in an era when we are in a

major construction phase for new power plants and transmis-sion infrastructure?

Yes, construction of new power plantsand transmission lines may be inevitable,but appropriate deployment of energy effi-ciency could have an impact, and perhapseven a significant impact, on how manyplants are built and how soon Wisconsinwill need them. With all that is at stakefrom an electric rate and environmentalperspective, we simply cannot afford toallow current barriers to using our mostcost-effective and cleanest solution —energy efficiency — to persist.

Currently, each Investor-Owned Utili-ty (IOU) is allowed to make a return on itsfixed-cost investments for each unit ofelectricity sold, which is 11.5 % perannum. Like any other businesses, the util-ity’s objective is to maximize profits inorder to meet its obligation to sharehold-ers. This means they are selling as manykilowatts of electricity to its customer aspossible.

In this scenario, the Wisconsin industrial community as thelargest users of electricity has the most to lose, because higherelectrical costs could make the difference between new job cre-ation and job destruction, between growth and contraction.

Given the fact that the cleanest, least expensive kWh is theone not used and saved for the next customers, why doesn’tWisconsin use the “shared savings” regimen currently beingemployed by Alliant Energy? This would allow utilities thesame return on investment for provable energy efficiencies asthey receive for new or existing sources of electricity?

Ultimately, what makes the idea of utility programs forenergy efficiency so compelling is that it establishes practical,enforceable rules, whereby large energy efficiencies could beachieved and documented. The potential for such an approachis enormous, because: (1) it is not being done to any extentnow; (2) utility programs can help increase market penetration,because they know their industrial customers best; (3) the aver-age Wisconsin industrial customer spend between $40,000 to$60,000 per month, which means each industrial company canpotentially save large amounts of electricity; (4) with the oppor-tunity for profit, utilities can now provide the necessary per-sonnel and capital to test new and existing technologies,because they would receive a return on investment for them;

and finally, (5) they can provide their business and industrialcustomers with objective advice about the array of energy effi-ciencies, helping them identify the most appropriate for eachcustomer.

Not unlike many other states, Wisconsin has accepted thenotion that the utilities should not beallowed to administer and implement anyconservation efforts, usually for the “foxwatching the henhouse” reason. With theadvancement of measurement and verifi-cation technologies, Wisconsin’s utilitiescan now demonstrate with certainty theamount of energy saved in real time.

The fact is that utilities and regulatorsneed to be able to treat energy efficiencyas a supply side option. Then, we canallow utilities to create and manage a port-folio of energy efficiencies not unlikewhat we have done with renewables. Thisnew approach is a “clean energy portfo-lio” and it is already being used in oneform or another in Vermont, Pennsylvania,Nevada, Oregon and California.

The six most important conditions forachieving the maximum amount of energyefficiency in Wisconsin’s energy futureare:

1. Energy Efficiency must be measurable, verifiable andsustainable.2. Utilities should earn a Rate of Return on Energy Effi-ciency. Treat Energy Efficiency as a supply side resourceacquisition.3. Energy Efficiency should be target based, incorporatingload growth, and part of the supply side resource portfo-lio. 4. Energy Efficiency should provide for participation byall customer classes. 5. There should be no means test on project ROI.6. Energy Efficiency and Demand response should beincorporated in all future resource requirements. The major point is that energy efficiency in the commer-

cial/industrial sector is an economic development issue, where-by Wisconsin can make our manufacturing and service econo-my more competitive. Energy efficiency is not a social pro-gram or corporate welfare; it is an economic imperative. Withthat in mind, it seems eminently practical to align Wisconsin’sutilities interest with the Public Service Commission, ratepay-ers and the commercial & industrial community. Wisconsinneeds to creates incentives for all of its utilities to help theircommercial and industrial customers save energy.

VIEWPOINT

FREE ALL WISCONSIN UTILITIES TO MAKEMONEY HELPING CUSTOMERS SAVE ENERGY

By Stephen Heins, VP of Corporate Communication, Orion Energy Systems

ET_1_06(Jan) 1/30/06 4:22 PM Page 14

plagues SCADA operations. Unlike inPlants, SCADA bandwidth is at a premi-um. Due to telephone and telemetry lim-itations such as distance, weather, radionoise, and other conditions, bandwidthusually remains at a meager 300bps to9600bps. Communication between theSCADA Master and the associated RTUsmust be reduced to minimum levels. It isextremely important that the OPC Serverbe able to differentiate between the twoOPC read types: cache and device readrequests. A “cache read” enable theSCADA Master to read the data in theOPC Server’s existing buffer. Cachereads are used in slow processes wherethe absolute latest values are notrequired. The advantage is a very fastresponse from the OPC server, and caus-es no polling sequence interruption of theRTUs. To get the latest values from theRTU, the SCADA Master must issue a“device read.” A device read causes theOPC Server to stop its regular round-robin polling sequence, and retrieve datafrom the selected RTU. The advantage of

a “device read” is that it provides themost recent values, however, it takesmore time to execute, and slows downthe entire system’s performance. Thus,the differentiation between cache anddevice reads will save the SCADA sys-tem from resource-hogging reads. Thisdifference also enables the OPC server toimplement priority of operations, whichare of interest especially when timelydata is required, such as in AGA (Ameri-can Gas Association) reads.

OPC SERVERS ARE NOTA COMMODITY

Although OPC makes it possible tohandle the specific issues posed bySCADA operations, the actual featureimplementation is left up to the softwaredevelopers, so it naturally follows thatOPC SCADA servers are not createdequal. Sophisticated buyers will researchtheir requirements, and ask for themexplicitly. Unfortunately, OPC serversthat work well in a plant environment donot necessarily work well in SCADAapplications. For instance, a simplesearch on the Internet will reveal manyOPC servers that support the popular

Modbus protocol; but only a small per-centage actually supports Modbus for usein SCADA. Some vendors even offerseparate OPC servers for plant andSCADA purposes, so check with yourOPC vendor to ensure you are gettingwhat you require.

Thus, OPC and SCADA can behighly compatible concepts. Integratorsmust carefully research and plan theirprojects to be successful. The SCADAapplications are more difficult to supportthan their plant-based cousins, since theyrequire special provisions for low band-width and noisy communication with amultitude of devices. But, when theserequirements are fulfilled, integrators caneffectively deploy OPC servers in aSCADA environment.

Randy Kondor, B.Sc. Eng. CompE, is theOPC Product Manager at Matrikon.Randy is responsible for Matrikon’s OPCbusiness unit which is comprised of over50 full time employees. Since 1996,Randy has been vastly involved withinthe OPC industry and a strong supporterof the OPC Foundation.

Nynas Canada, inc. Telephone: (905) 804-8540. E-mail: pierre.barras@nynas.com www.nynas.com

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OPCcontinued from page 12

ET_1_06(Jan) 1/30/06 4:22 PM Page 15

Electricity Today16

Recent additions to Ontario’sgenerating capacity andplanned market enhance-

ments in the first half of 2006 contributeto a more positive outlook for Ontario’soverall supply adequacy picture over thenext 18 months.

The overall outlook for resourceavailability continues to indicate that formost weeks during the 18-month outlooktime frame, there are sufficient resourcesto meet the present resource require-ments, under the normal weather demandscenario. Under extreme weather condi-tions, the outlook results continue toidentify significant reliance on imports inmany weeks, to meet resource require-ments.

While the overall supply situationappears adequate concerns remain in anumber of areas within Ontario, particu-larly in the Greater Toronto Area (GTA)where the need for new supply and trans-mission facilities is particularly urgent. Itis also critical that more efficient regula-tory approvals processes be developed inorder to enable timely implementation ofthe required new generation and trans-mission facilities.

The Independent Electricity SystemOperator (IESO) regularly assesses theadequacy and reliability of Ontario’spower system. This 18-month outlookprovides our assessment of the reliabilityof the Ontario electricity system fromJanuary 2006 to June 2007. The assess-ment uses the most up to date forecastinformation and considers experiencegained from past operations.

A number of changes are forecast forthe Ontario electricity sector to addressthe risks in the GTA and to implementthe provincial government’s plan for coalreplacement and a transition to cleanerforms of generation. The IESO is moni-toring the progress of the inter-relatedgeneration, transmission and demandmanagement projects underway andplanned and the resulting impact on reli-ability.

EXPERIENCE GAINED FROM PASTOPERATIONS

There were a number of challengesto maintain reliability of Ontario’s bulkpower system during the summer of2005. Soaring temperatures brought sig-nificant demand and drought-like condi-tions limited hydroelectric generation,resulting in a continued strain on thepower system.

The IESO relied on extensive use ofEmergency Control Actions in order tomaintain reliability and avoid powerinterruptions. Public appeals urging cus-tomers to cut back on electricity con-sumption were issued on 12 separatedays, five per cent voltage reductionswere implemented across the province ontwo days in August with two additionalvoltage reductions implemented in theGTA. This occurred despite good perfor-mance and availability of the Ontariogeneration and transmission facilities andthe support from neighbouring markets.

Increased supply brought into ser-vice in the fourth quarter of 2005 (515megawatts from Pickering Unit 1), aswell as changes proposed by the IESO toput imports into Ontario on a moresecure footing during times of need,

should improve the supply-demand situa-tion and help reduce the likelihood of arepeat of the events of the past summer.

A Reliability Demand ResponseProgram similar to those of neighbouringmarkets is being developed for the sum-mer of 2006 to give more certainty thatan IESO request for demand responsewill be followed and to allow for activa-tion earlier in the list of control actions.

To increase the certainty of capacityand energy availability through day-ahead arrangements, the IESO is work-ing with stakeholders to implement aDay Ahead Commitment Process for thesummer of 2006.

In the western GTA, and in centralToronto, transformer load levels werenear, and in some cases exceeded theircapability in summer 2005. The need fortransmission enhancements and new sup-ply to unload these transformers contin-ues to be a priority requirement for theIESO.

Outside the GTA, the transmissionsystem is expected to be adequate to sup-ply demand under the forecast conditionsstudied in this outlook, with some excep-tions. Limitations experienced over the

continued on page 18

TRANSMISSION AND DISTRIBUTION

IESO ISSUES ASSESSMENT OF THE RELIABILITYOF THE ONTARIO ELECTRICITY SYSTEM

ET_1_06(Jan) 1/30/06 4:22 PM Page 16

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Arc-resistant retrofits provide through the doorracking of circuit breakers,reducing the risk of workerinjury in the event of a failure and eliminating theneed for flash suits.

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Arc-resistant retrofits provide through the doorracking of circuit breakers,reducing the risk of workerinjury in the event of a failure and eliminating theneed for flash suits.

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ET_1_06(Jan) 1/30/06 4:22 PM Page 17

Electricity Today18

summer of 2005 in the Windsor area, northward into the Hamil-ton-Burlington area, and westward from the St. Lawrence trans-former station limited the use of available Ontario generationand/or limited imports into the province during hot weather,high-demand periods.

Changes and upgrades are underway, and will improve butnot completely relieve the situation for summer 2006.

OTHER CONCERNSThere is a number of growing reliability risks that need to

be addressed during this assessment period in order to havetimely solutions available.

Toronto currently relies on supply generated outside thecity to meet demand. The main transmission paths and relatedfacilities carrying this power into the city are already nearingcapacity.

New generation must be installed by the summer of 2008to address the risk of rotating power cuts to areas of centralToronto during periods of high demand. Increased demandresponse and conservation efforts will reduce but not eliminatethe need for new supply. The IESO is working with the OntarioPower Authority to address the need for new supply in Toronto.But in the absence of a viable, approved plan, timely resolutionis at risk. The IESO will continue to work with stakeholders toassess the needs and develop options.

Even with new generationinstalled by 2008, the risk willagain grow to unacceptable levelswithout new transmission, requir-ing a third transmission path intoToronto early in the next decade tomaintain reliability under extreme-ly hot summer weather conditions.

New supply and transmission is also required in the west-ern GTA to address overloading of transmission facilities sup-plying the GTA, to meet the forecast growth in demand and tocontrol voltages in the area.

The recently announced Goreway natural gas units inBrampton will substantially reduce the reliability risks in the

area but not completely remove them. Transmission facilitiesand lines serving the area exceeded their long-term emergencycapability and the IESO’s supply deliverability guidelines insummer 2005. A combination of new generation and transmis-sion enhancements are required to address this. Necessarytransmission solutions under discussion are likely to berequired to provide time for the development of additional sup-ply projects.

MORE EFFICIENT REGULATORY PROCESSES REQUIREDThe current regulatory approvals process is complex and

will impede the installation of new facilities in time to addressprojected reliability concerns. Given the amount of new supplyand transmission enhancements required in such a short periodof time, timely regulatory approvals processes are required.Serious consideration needs to be given to developing expedit-ed, but thorough, approvals processes to ensure timely imple-mentation of the new facilities.

DEMANDEnergy demand is expected to be 157.0 terawatt hours

(TWh) for 2006, a 1.3 per cent increase over the projected ener-gy demand for 2005 (154.9 TWh). The expected seasonal peakdemand for the winter of 2006 is 24,899 MW. The expectedseasonal peak for the summer 2006 is forecast to be 25,917MW.

The following table shows the peak demand forecasts forthe seasons covered in the Outlook period.

While extreme weather conditions have a lower probabili-ty of occurring, history shows that even seasons with averageweather will include periods of extreme weather Prudent plan-ning dictates that the system be capable of operating reliablyduring extreme weather periods without significant use ofemergency control actions.

IESOcontinued from page 16

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ET_1_06(Jan) 1/30/06 4:23 PM Page 18

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Periodic and continuous monitoring of partial discharges to detect deterioration of stator winding insulation for medium and high voltage equipment.

POWER

ET_1_06(Jan) 1/30/06 4:23 PM Page 19

Electricity Today20

"Rolling the Dice: thepolitics of the powerindustry" is the latest

conference being put on by the Indepen-dent Power Producers Society of Alber-ta. Running from March 12-14, 2006in the rocky mountain resort of Banff,Alberta, Canada this year's theme tack-les the industry's universal challenge.

Whether it’s siting issues, or envi-ronmental policy or concern with price,the power industry is faced with someunique constraints. It is also true thatthese challenges are faced by both reg-ulated and restructured power markets.

While we won't propose to answerthese issues over two days, the programfeatures industry leaders from acrossNorth America who will review keymarket developments and provide theirperspectives on the conference theme.

Some of our speakers include:Louise McCarren,

CEO, Western Electricity Coordi-nating Council;

Greg Melchin, Minister of Energy, Government ofAlberta;

David Goulding, President, Independent ElectricitySystem Operator (Ontario);

Hal Kvisle, President and CEO, TransCanadaCorporation; and

Gary Holden, President and CEO Enmax Corpo-ration.

We welcome our more than 500conference participants, who representthe spectrum of the industry, includinggenerators, consumers, regulators andconsultants. They also come from mar-kets as diverse as PJM and the PacNW.

More information about IPPSA,including the conference program, isavailable at www.ippsa.com

CONFERENCES

IPPSA 12TH ANNUAL CONFERENCE & TRADE SHOWMarch 12-14, 2006www.ippsa.comBy Evan Bahry, Executive Director, IPPSA

FAIRMONT BANFF SPRINGS CONFERENCE CENTRE

IPPSA 2006

Exhibitor list:

Company BoothABB Inc 17AltaLink Management Ltd 8Canadian Hydro Developers Inc 19Canadian Wind Energy Association 18GE Energy 6Innovative Steam Technologies 15IPPSA 4MIDAS Metering Services Ltd 16Montana Alberta Tie Ltd 3NrgStream 7The Oxford Princeton Programme 11Pratt & Whitney Power Systems 14Trackflow 12Vision Quest Windelectric 5ZE Power Group 13

ET_1_06(Jan) 1/30/06 4:02 PM Page 20

h

ET_1_06(Jan) 1/27/06 3:41 PM Page 21

Electricity Today22

Ontario’s utilities already havetheir hands full ensuring thatthe lights stay on and the fac-

tories keep humming - so allocatingmoney and resources for innovativeresearch gets pushed to the back of theline.

Cognizant of these realities, theLDC Tomorrow Fund provides fundingfor research projects and finances energyinnovation and opportunities for LocalDistribution Companies (LDCs) in theprovince.

“We were established to enhance thecompetitiveness of utilities, to fund pro-jects that will show how things can bedone better and more effectively, throughinnovation,” says Fund chairman DaveSinclair, President and CEO of KenoraHydro.

Funding is available to all LDCs,government agencies, academic institu-tions and those who work in the electric-ity industry. Funding decisions are by aboard of trustees and administration isconducted by The MEARIE Group.

Criteria for funding are:- that the applications must be relat-

ed to the development of commercialopportunities within the electricity mar-ket of Ontario;

- projects are expected to be signifi-cantly beneficial to the majority of LDCs

in Ontario over the short and mid-condi-tions in the new competitive market;

- projects must represent advance-ment of technology, procedures, knowl-edge, and experience; and

- recipients of funding must be pre-pared to share results and make presenta-tions on the results of the project.

“The projects that are currently inprogress are the electrical thermal stor-age units project, the residential powerfactor correction project and the broad-band-over-powerline for smart meteringproject,” says Mr. Sinclair.

The thermal storage project is beingcarried out by Peterborough DistributionInc., with Whitby Hydro working on theresidential power factor correction pro-ject.

“The thermal storage units - like theresidential correction project - are allabout shifting load,” he says. “It’s a mat-ter of shifting peak load demand to off-peak times.”

In the case of the thermal storageunits, they would consume power duringoff-peak times and emit heat during peakdemand hours, “flattening the load” forlocal utilities.

In the case of power factor correc-tion, it was simply a matter of applyingtechnology that has been used in anindustrial setting to the residential con-sumer.

The Whitby Hydro study revealedthat the average power factor when theunits were working was over 99 per cent,compared to the normal 87 per cent whenthe units were turned off.

“We want to enhance the competi-tiveness of utilities, and projects likethese the potential that is out there,” saysMr. Sinclair.

“Utilities have been stretched to themax, struggling just to meet the day-to-day demands of providing a service forcustomers,” he says. “They don’t havethe resources to do the research.

“With the Fund, we can share thefindings of the research with the LDCs; itis to the betterment of everyone.”

Although the vast majority of LDCsand other parties haven’t taken advantageof the Fund to date, Mr. Sinclair is confi-dent that more LDCs will come on boardonce they see the benefits to be gained.

“I think it (the Fund) will hit a criti-cal mass, with more and more utilitiesseeking funding once they get a betterunderstanding of what is available,” hesays. “And this will spawn additionalinnovation.”

For more information on the LDCTomorrow Fund, you can contact TheMEARIE Group at www.mearie.ca, andclick on the Products/Services and theLDC Tomorrow Fund icon.

ET

RESEARCH & DEVELOPMENT

TOMORROWFUND OFFERS A HELPINGHAND TOSTRESSED-OUTUTILITIES

By Don Horne

The LDC Tomorrow Fund provides money for utility research and innovation.

ET_1_06(Jan) 1/27/06 3:41 PM Page 22

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“Keep up the good work. You have aknack for selecting an interesting arrayof topics.”

Dick Essig, Senior Analyst withGlobe Research Associates in Riverside,California writes:

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23January 2006

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Electricity Today24

Local manufacturers of motorsand generators must nowcompete with other manufac-

turers from around the world. The resulthas been pressure on the manufacturersto reduce costs through process..Improvements, using new materialsand/or increasing design stresses.

The stator winding of air-cooledmotors and generators has been a partic-ular focus for cost reduction or converse-ly rated power increases in the same sta-tor frame inevitably, the adoption ofthese new approaches has resulted insome problems and even failures, some-times just a few years after the machine iscommissioned.

This article provides examples ofpremature stator winding insulationaging problems, including failurescaused by poorly applied PD protectionlayers, coils installed too close togetherin the endwinding,coils that abraded dueto inadequate bracingin the slot as well asproblems associatedwith the global VPIprocess. This anecdo-tal information aboutthe perceived increasein the premature fail-ure rate is validatedby a statistical analy-sis of on-line partialdischarge data thatshows that somebrands have seen alarge increase of PDin machines made inthe past 10 years.Some suggestions aremade that may enablemachine owners toreduce the risk of pre-mature winding fail-ure.

INTRODUCTIONAs part of the analysis of on-line

partial discharge (PD) data performed onthousands of motors and generators, ithas been noted that stators made by somemanufacturers in the past decade havemuch higher PD than stators made by thesame manufacturer more than 10 yearsago [1]. For example, Figure 1 shows thepeak PD activity vs. winding manufac-turing date for 9 of the world’s largestmanufacturers of air-cooled motors andgenerators. This figure shows that for on-line PD readings measured in 2003, fourmanufacturers are exhibiting much high-er PD on recently made stators, than theytypically experienced on their machinesmade before 1995. Since high PD can beoften associated with rapid aging of thestator winding insulation system, thehigh PD in recently manufactured statorsis of concern.

Maughan has recently published acatalog of premature winding problemshe has seen [2]. This paper presents addi-tional examples of advanced insulationaging that this author has recently seen inair-cooled motor and generator stators.Many of these deterioration processesresulted in premature winding failure.This paper also postulates reasons whysome recently made stator winding insu-lation systems have higher PD activity,and some steps the user may take toreduce the risk of premature stator wind-ing failure.

ELECTRIC STRESS CONTROL COAT-ING PROBLEMS

Most stator windings rated >6 kVemploy a carbon-loaded paint or tape onthe surface of the coils or bars in the slot[3]. This ‘semicon’ coating prevents PDbetween the surface of the coil and thestator core in any small air gap that

GENERATION

EXAMPLES OF PREMATURE STATOR WINDINGFAILURE IN RECENTLY MANUFACUTRED

MOTORS AND GENERATORSBy G.C. Stone, Iris Power Engineering

Figure 1: Peak PD activity versus year of manufacture for 9 major manufacturers

ET_1_06(Jan) 1/27/06 3:41 PM Page 24

inevitably exits at this interface. In addi-tion, most manufacturers use a siliconcarbide-loaded paint or tape on the coilfor 10 cm or so outside of the slot. Thissilicon carbide coating overlaps thesemicon coating, and reduces the highelectric field that would otherwise existat the end of the semicon coatings.

In the 1970s, there were a number ofmachines that exhibited very high PDand high ozone concentrations fromeither or both coatings that were causedby manufacturing problems. The prob-lems seemed to originate from coatingswhere the carbon and/or silicon carbidewas non-uniformly dispersed in the insu-lation matrix or where the applicationmethod resulted in microvoids just underthe coating. In both cases the result wasPD. This high PD created ozone thatchemically attacked the insulation (notto mention heat exchanger metal andrubber components) and properly madeareas of the coatings, resulting in thespread of the problem. This problemseems to be worse if the winding insula-

tion operates at higher electric stressand/or higher temperature. Perhaps it isfor this reason that there seems to be arecurrence of this problem in the pastfew years.

Figure 2 shows a hydrogeneratorstator where a very noticeable whiteband is visible at the junction of thesemicon coating and the silicon carbidecoating. Figure 3 shows a winding wherethe semicon has virtually disappeared inthe slot due to poor application of thesemicon coating.

ENDWINDING PDCoils operating at high voltage and

placed adjacent to other high voltagecoils in another phase require a mini-mum separation to avoid PD in the airspace between coils. This PD will gradu-ally erode the groundwall insulation andmay lead to phase-to-phase stator failure.The higher the voltage class of themachine and the thinner the groundwallinsulation, the greater must be the spac-ing [3].

Unfortunately, in many motors andgenerators we have noted inadequatespacing, and consequently high PD (andozone). Figure 4 shows the white residuecaused by ozone resulting from PDbetween two coils in different phasesthat were installed too close to one-another.

Figure 5 shows a stator where theclose spacing has resulted in highlystressed air adjacent to where two phaseend coils (in different phases) make con-nection to the circuit ring bus. Theresulting partial discharge eventually

January 2006

Continued on Page 26

Figure 2: Semicon and grading coatingoverlap deterioration due to poorlyapplied or inadequate coatings

Figure 3: Destruction of the coil semiconcoating in the stator slot due to PD andozone

Figure 4: PD occurring between high volt-age coils in two different phases, where thespacing is insufficient to prevent the PD.Note that the spacing between adjacentcoils is irregular, as a result of poor manu-facturing processes.

ET_1_06(Jan) 1/27/06 3:41 PM Page 25

Electricity Today26

bores a hole through the insulation, trig-gering a phase-to-phase or a phase-to-ground fault.

LOOSE COILS IN THE SLOTCoil vibration in the slot has long

been a problem in all non-global VPI sta-tors made with thermoset insulation sys-tems such as epoxy mica. The firstinstances were reported over 50 yearsago [3]. The root cause of the problem isthat at full load, the twice power frequen-cy magnetic forces will vibrate the coilsif the coils are not tightly held in the slot.Consequently, the groundwall insulationrubs against the laminated steel core – avery abrasive surface. First the semicon-ductive layer of the bar or coil is abradedaway, and then the groundwall insula-tion. The mechanism is sometimes

referred to as slot discharge,because once the semiconduc-tive coating is abraded, partialdischarges occur between thecoil surface and the core, fur-ther increasing the rate of dete-rioration.

Figure 6 shows a coil thatwas removed from the slot of ahydrogenerator where thesemicon and about 30% of thegroundwall thickness has beenabraded away. The manufac-turer had not mechanicallysecured the coils in the slots bymeans such as sidepacking,ripple springs, two partwedges, conformable restraintin the slots, etc. Figure 7 showsa bar in the process of beingremoved from the stator slot that showssignificant abrasion of the insulation inthe slot, for the same reasons.

Normally one would not expectloose coils to be a problem in a globalVPI stator, since the coils are effectivelyglued to the stator core. However, if thecoils are made too small for the slot, andare subjected to load cycling that createsshear stresses between the coils and thestator core, then loose coils and slot dis-charge may occur in some designs (Fig-ure 8).

AVOIDING PREMATURESTATOR FAILURE

The premature failures describedabove were a consequence of the designand/or manufacture of the stator. Specifi-cally:

• The electric stress control prob-lems may be caused by poorly appliedcoatings. The deterioration process isaccelerated in winding designs that causea class F insulation system to operateabove about 120C and/or with an averagegroundwall electric stress above 3kV/mm.

• The endwinding PD is probablycaused either by: (a) poor dimensionalcontrol of the coil and/or inconsistentalignment of adjacent coils in the slots;(b) too short an endwinding which doesnot allow enough circumference at thecoil ends for sufficient air spacingbetween the connections; and/or (c) inat-tention to the air space and creepage dis-tances needed when blocking and brac-ing are installed.

• The loose coil in the slot problemsmay be due to a slot content design thatdoes not take into account the gradual

shrinkage of insulating and wedgingmaterials, or where the need for tightcoils has been sacrificed to make thecoils easy to install in the slot.

Probably the best way to avoid pre-mature stator winding insulation prob-lems is to have an adequate purchasetechnical specification. Some sugges-tions for terms to include in such a pur-chase specification, in addition to the rel-evant parts of IEC 60034, are:

• For a 30-year life, require a Class Finsulation system to be operated at aClass B temperature rise.

• Require that the groundwall insula-tion system pass a voltage endurancetype test similar to those specified inIEEE Standards 1043 and IEEE 1553(regrettably there is no IEC equivalentspecification that is well defined and hasa pass-fail criteria). Requiring a voltageendurance test is probably better thanspecifying the maximum design electricstress, since this may retard the introduc-tion of new materials and processes. Forfurther assurance, require spare coilsfrom the production batch for a stator tobe subjected to a voltage endurance test.

• Require a partial discharge test onthe new winding, together with a ‘black-out’ test to ensure the coils are properlyimpregnated, and clearances in the end-winding are sufficient [4,5].

• For multi-turn coils, require a volt-age surge test both on coils (for non glob-al VPI stators) and complete windings,according to IEEE 522 (IEC 60034 Part15 is not as effective in detecting weakturn insulation).

• For non-global VPI stators, requirethe use of a wedging or sidepacking sys-tem that contains a follow-up restraint

Stator Windingcontinued from page 25

Figure 6: Photo of a coil removed from a hydrogener-ator stator that failed due to slot discharge. The verti-cal stripes are where the insulation is not abraded,since the stator core ventilation ducts are at these loca-tions.

Figure 5: Partial discharges occurring inthe inadequate space (here filled with aninsulating board) between two phaseswhere the high voltage bars are connectedto the circuit ring busses. (Courtesy C.Maughan)

ET_1_06(Jan) 1/27/06 4:30 PM Page 26

that ensures tightness as the slot contentsshrink. This could include the use of twoor three part wedges, ripple springsand/or conformable materials such as sil-icon rubber. Alternatively considerrequiring a clearance between the side ofthe coil and the core to be no more than0.1 mm or so.

• Insist on the right to make unan-nounced factory inspections during man-ufacture of the stator.

Note that most of the above termsmay increase the cost of the stator wind-ing, but will probably result in a longerwinding life and less maintenance overthe lifetime. The machine owner also hasa responsibility to operate the machinewithin specification, keep the windingsclean and tight, and preferably visuallyinspect the winding before the end of thewarranty period. It would also be benefi-cial if manufacturers could educate userson the trade-offs of cost vs. life theymake when designing a new winding.

CONCLUSIONS.1. Problems such as coil abrasion in

the slot, electric stress relief coatingdeterioration and partial discharges inthe endwinding have lead to failures in asshort as 5 years of operation. This anec-dotal information is supported by the factthat PD for some manufacturers is high-er for recently made machines than forsimilar machines made over 10 yearsago.

2. To avoid premature failures, usersof modern air-cooled machines shouldensure they have a good purchase speci-fication and ensure the manufacturer hasan appropriate QA program in place.

REFERENCES[1] G.C. Stone, V. Warren, “Effect of

Manufacturer, Winding Age and Insula-tion Type on Stator Winding PD Levels”,IEEE Electrical Insulation Magazine,Sept 2004, p13.

[2] C.V. Maughan, “Root CauseDiagnostics of Generator Service Fail-ures”, Proc IEEE International Sympo-sium on Electrical Insulation, Sept 2004,p154.

[3] G.C. Stone et al, “Electrical Insu-lation for Rotating Machines”, Wiley-

IEEE Press, 2004[4] G.C. Stone, “A Suggested

Approach for Specifying PD Testing as aNew Winding Acceptance Test”, Proc.IEEE Electrical Insulation Conference,Oct 2005, p159

[5] Draft IEC Standard IEC 60034Part 27, “Rotating Electrical Machines –Part 27 PD Measurements on the StatorWinding Insulation of Rotating Machin-ery”, Oct 2005.

27January 2006

Figure 7: Bar abrasion due to loose windings in the slot of aturbo generator that did not have sufficient sidepacking or aradial follow-up wedging system.

Figure 8: Example of loose winding failure in a 200 MVA globalVPI generator stator.

ET_1_06(Jan) 1/27/06 4:30 PM Page 27

Electricity Today28

The Ontario government’s smartmeter initiative represents one ofthe largest smart meter deploy-

ments in North America. In fact, imple-mented successfully, it could very wellposition Ontario as a leading proponentof smart metering worldwide. There islittle doubt that jurisdictions, particularlyin the United States, are watchingOntario’s progress closely as theprovince formulates a final implementa-tion plan to facilitate the deployment ofthis wide-scale venture.

As the industry players responsiblefor owning, installing, operating andmaintaining electricity meters, theprovince’s electricity distributors haveassumed a central role in laying thegroundwork for smart meter implementa-tion. However, this work is only an initialstep in the role distributors will play inthe ongoing data management, opera-tions and maintenance of the meters. Dis-tributors will continue on the frontline asthe port of call for customers and as theprimary billing agents for the electricitysystem.

On November 3, 2005, Ontario’sprovincial government tabled Bill 21, theElectricity Conservation ResponsibilityAct. The bill is being described as‘enabling’ legislation as it gives the gov-ernment the flexibility to determine thebest options for the governance, owner-ship and regulatory structures ofOntario’s smart metering initiative inmoving forward.

The long-anticipated legislation pro-vides the basic framework to facilitatethe government’s smart meter initiative,which will see the installation of close to4.5 million ‘smart’ meters in every resi-

dence and small business inthe province by 2010 (thefirst 800,000 are to beinstalled by 2007).

The initiative is part of abroader government com-mitment to create a ‘cultureof conservation’ in Ontario,designed to address peakdemand issues and the ongo-ing strain on electricity sup-ply in the province. With asupporting pricing plan thatwill come into effect on May1, 2006, the new time-of-usemeters are intended to be thetool that electricity consumers turn to inorder to respond to price signals in highand low peak periods.

And while the government has beenclear on its ultimate goals for the instal-lation and use of smart meters in Ontario,many of the operational and regulatorydetails of how smart meters will beinstalled and managed remain to be for-mulated. Further clarification will comein the form of new regulation, codes, andMinistry directives, which are expectedto flow from the new legislation intoearly 2006.

CLARIFICATION OF RESPONSIBILITIESIS CRITICAL NEXT STEP

Ontario’s electricity distributorsbelieve that the success or failure ofsmart meter implementation will ulti-mately depend on a clear and commonunderstanding of the responsibilities tobe carried out by each of the playersinvolved, including government and reg-ulators.

Electricity distribution companies

have come together and continue to workin industry groupings, tackling key oper-ational and regulatory issues, includingthe more technical aspects of functional-ity and meter data standards. This coop-erative approach is providing greater effi-ciencies and is allowing our sector todevelop best practices based on a collec-tive approach to testing through smartmeter pilots.

Just as importantly, key industrypartnerships between distributors andmetering companies are bringing togeth-er the technological and communicationssupport that will ultimately facilitate fullintegration of smart metering in theprovince.

In further formulating the smartmeter implementation framework gov-ernment can leverage these findings andthe data collected through smart meterpilot projects. Ontario’s distributors aresharing and consulting closely with gov-ernment decision-makers and regulatorsin order to further facilitate this impor-tant exchange of information.

SMART METERING

ONTARIO’S ELECTRICITY DISTRIBUTORS NEWLEGISLATION AND THE SMART

IMPLEMENTATION OF SMART METERS

Distributors have been clear from thebeginning that it is critical that utilitiesare kept financially whole through this

process. Mechanismswill need to be in placeto compensate distribu-tors for the prematureretirement of existingmeters (legacy assets),and the capital costs

associated with installing the newmeters must be fully recoverable.

By Charlie Macaluso, President and CEO of the Electricity Distributors Association

ET_1_06(Jan) 1/27/06 4:30 PM Page 28

Although we’ve come a long way, there is a lot of workyet to be done. We can be assured of one thing - key industryplayers are going to have to work together and with somedetermination to meet the tight timeline set by government of2010.

Ontario’s electricity distributors are keenly aware of theimportance of preparedness in such a large-scale initiative.Through cooperative industry planning distributors have beenlaying the groundwork, determining which meter technologiesaddress the geographic uniqueness of the province’s regions,as well as testing data and communication technologiesthrough ongoing smart meter pilot projects. The expertise andexperience that distributors are bringing to the table will go along way in ensuring a smooth and successful deployment.

The smart meter initiative will require the continuingcooperation and timely action of all key industry playersinvolved – government, regulators and electricity distributors.More than any other factor, this remains the vital componentthat will realize ultimate success in the smooth implementa-tion of the government’s smart meter initiative.

Charlie Macaluso is President and CEO of the Electricity Dis-tributors Association. The EDA is the voice of Ontario’s localelectricity distributors, the publicly and privately owned com-panies that safely and reliably deliver electricity to over fourmillion Ontario homes, businesses and public institutions. TheEDA provides members with advocacy and representation inthe legislative and regulatory environment and the electricitymarket in Ontario.

SMART METER ENTITY – MANAGING METER CONSUMPTION INFORMATION

AND DATABill 21 allows for the establishment of a Smart Meter Enti-

ty (SME) that will collect, store, manage and transfer meterconsumption information and data. The legislation providesgovernment a great deal of latitude on this front and consider-able flexibility regarding the ownership and structure of thedata entity that will ultimately be established. In fact, the SMEcould take its form as a ‘corporation, a limited partnership, apartnership, or an entity designated by regulation’.

While this process unfolds, electricity distributors arelooking to have three key issues addressed and clearly defined:

1. What the basic design of a smart meter system/datapathway will be;

2. What particular communication assets and functionsdistributors will have the right to own/control; and,

3. What exactly the responsibilities of the SME will be.With the assistance of an appointed technical advisor, the

government is expected to make a final decision on the respon-sibilities and structure of this important entity in the nearfuture. Ontario’s distributors remain engaged with governmentpolicy makers to ensure that certain basic parameters identifiedby our sector are addressed.

LEGACY ASSETS AND CAPITAL COSTSThe scale of the government’s plan is monumental. Mil-

lions of electricity meters will be disposed of and replacedwith close to 4.5 million new time-of-use meters. The OntarioEnergy Board has estimated the capital cost of new meters willbe approximately $1 billion.

Distributors have been clear from the beginning that it iscritical that utilities are kept financially whole through thisprocess. Mechanisms will need to be in place to compensatedistributors for the premature retirement of existing meters(legacy assets), and the capital costs associated with installingthe new meters must be fully recoverable.

Importantly, Bill 21 allows the Ministry to issue directivesto the Ontario Energy Board to allow distributors to recoverthose costs associated with smart meter deployment throughthe rate base. It also provides the Minister with the authority tomake regulation relating to the establishment of varianceaccounts and the legislation puts in place a framework for therecovery of costs, including the recovery of stranded metercosts.

Ensuring that the proper cost recovery mechanisms are inplace as the smart meter initiative proceeds remains anabsolutely critical consideration for Ontario’s distributors inmoving forward.

NEXT STEPS IN MOVING FORWARDThe proposed legislation will go to the Legislative Com-

mittee in early February 2006, before it goes back to the Housefor third and final reading. Bill 21 will likely be passed intolaw sometime in the late winter.

There is little doubt that jurisdictions across North Amer-ica are watching with interest as Ontario works through thefinal details of implementation.

We are on a cusp as government formulates a definitiveframework for the plan. Attention also shifts to the OntarioEnergy Board, who will have to put appropriate regulations inplace in order to facilitate that plan.

29January 2006

ET_1_06(Jan) 1/27/06 4:30 PM Page 29

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SMART ENERGY POLICY RESEARCHREPORT - EMPOWERING CONSUMERS

(THE DEMAND SIDE)For any market to work properly,

demand and supply must both activelyseek the price that clears that market. Inelectricity, Texas has done a far better jobof opening its market to new suppliersthan it has of empowering customers toexpress their demand. Customers mustbe empowered to participate — withtimely price information and the tools tocontrol how and when they use energy —if the Texas model will be one in whichprice is truly set by the competing forcesof supply and demand. As the Texas stategovernment transitions from a role ofregulating monopoly utilities to that ofmonitoring a market, demand participa-tion is a crucial counterbalance to theconcentration of supply-side marketpower.

In order to avert crises such as therolling blackouts and runaway pricespikes that crippled California in 2000and 2001, a framework must be estab-lished to enable the market to respond topeak demand challenges. Broad cus-tomer participation in the market — sup-ported by effective programs enablingdemand elasticity through peak loadmanagement, energy efficiency, andbehavior modification—is critical tomoderating price swings, protecting con-sumers, and minimizing the negativeimpact on the environment.

These forces - supply and demand -collide at the electric meter. Large indus-trial customers in Texas are required tohave advanced meters that measure usagein 15-minute intervals, enabling them toleverage excellent rates and even partici-pate directly in the wholesale market. Butfor 99-plus percent of Texas customers,meters are electromechanical devicesthat produce only a total of kilowatt-hours, which is then multiplied by anaverage rate to produce an electric bill.

Traditional meters are thus incapableof providing the true picture. By discon-necting customers from the cycles of the

wholesale electricity market — ostensi-bly to “protect” them from price spikes— they force customers to overpay formost of the power they use, and deprivethem of the opportunity to take advantageof lower, off-peak rates. Flat-rate pricingincludes expensive “insurance premi-ums” which are the direct result of a needto invest hundreds of millions of dollarsannually for a power-generating infra-structure built to serve peak loads thatlast only a few dozen hours each year.

Advanced meters, combined withtime-sensitive price options from suppli-ers, can provide the market with the vitalcharacteristic of demand elasticity — inshort, the ability of consumers to managetheir energy consumption in response toprice signals. By reducing consumptionduring peak periods, the demand elastic-ity would reduce the amount of generat-ing capacity needed to meet peakdemand, and improve the utilization ofthe grid and generation assets. Researchhas repeatedly shown that even modestdemand reductions by some customersduring peak use periods have dramaticpositive effects on prices for all usersduring those periods. The Electric PowerResearch Institute (EPRI) has found thatif only 10 percent of the overall customerload is exposed to real-time pricing,resulting customer demand reductionscan reduce price spikes for all customersby 33 to 66 percent.

Eric Hirst, the industry-leading ana-

lyst formerly of the Oak Ridge NationalLaboratory, has studied actual experiencein energy markets nationwide to illustratethe potential of customer participation indemand response. His model based onmarket conditions in

California and the northeast revealedthat a 5 percent reduction in peakdemand had the result of reducing peakpower prices by more than 50 percent.

Hirst has also evaluated the mass-market economic effect of residentialtime-of-use (TOU) rates as a demandelasticity resource. One such analysisstudied prices and market conditions spe-cific to the Pacific Northwest. Assumingan average level of price volatility and20% participation by residential cus-tomers in optional TOU rates, Hirst pro-jected that wholesale electric prices forthe year would decrease by $280 million,or 5.5% of a $5.2 billion Oregon/Wash-ington market. Significantly, part of thecost reductions were attributed to thereduced need for new generation plantsand transmission lines, meaning thatreduced exposure to wholesale peakslowers costs for transmission and distrib-ution companies and retail providersalike. In a competitive market, this canresult in lower prices for all consumers,even those who do not participate intime-based rates.

CHALLENGES IN SYSTEM RELIABILITYAs Californians learned the hard

SMART METERING

THE CASE FOR ADVANCED ELECTRICITYMETERING IN TEXAS - PART II

ET_1_06(Jan) 1/27/06 4:30 PM Page 30

way, balancing supply and demand forelectricity is an increasingly challengingproposition, especially in areas typifiedby weather extremes, transmission linecongestion, and inadequate reserve gen-eration capacity. And while the supplysurplus in Texas can be partially attrib-uted to a favorable regulatory climate,there are signs that market forces arealready working to erode the comfortablecushion. Twelve of 29 scheduled genera-tion projects were cancelled or shelved inlate 2001 and early 2002, the result ofmarket decisions by private companiesno longer beholden to state regulators.

One of the state’s largest generationcompanies, American Electric Power, hasmothballed eight plants and hopes tomothball eight others, pending approvalby the Electric Reliability Council ofTexas (ERCOT). Texas Genco, an unbun-dled affiliate of the former Reliant HL&Pvertical utility, announced in October2002 that it intends to mothball six plantswith a total of 3,400 MW of capacity.Nationally, the overall economic viabilityof independent “merchant” power

providers has been called into question asmany have found it difficult to compete.Eventually, these capacity reductions andthe uncertainty of the merchant powermarket could have a substantial impacton the Texas reserve margin. Meanwhile,plants that ERCOT requires to remainoperable in order to ward off supplyemergencies will be supported by costly“Reliability Must Run” contracts, whichpay the generating companies to keep theotherwise-uneconomic plants on call.

When the processes of planning,constructing, and retiring power plantsare subjected to the cycles of a free mar-ket, a soft cycle such as exists today caus-es excess capacity to decline, as idleassets do not produce profits. As formerTexas Public Utility Commissioner BrettPerlman has noted, “No one benefitsfrom having excess capacity. No onewants to pay for it.” When the marketinevitably emerges from its soft cycle,the reduced capacity places more relianceon peaking plants that were previouslyfired up only at times of extremely highdemand. This strong phase of the market

is typified by reliability challenges, andthe kind of price spikes that encourageinvestment in generation facilities. Newplants take years to permit and build,however, and when market cycling out-paces construction, the result can be awindow of insufficient reserve margin.

A more serious short-term concern isthe fact that the state’s current generationcapacity is not all located convenientlynear the load, and the government’s abil-ity to control the location of new genera-tion has also been severely curtailed inrestructuring. One result has been chron-ic transmission line congestion, whichhas cost the market over $300 millionannually in “uplifted” charges as dis-patchers were required to purchase moreexpensive power in order to avoid trans-mission failures on congested lines. ThePUCT has launched a massive three-yearproject to redesign the wholesale marketby transitioning to a “Nodal” system ofpricing, in which local congestion costsare built into the cost of electricity. Texas

31January 2006

Continued on Page 32

ET_1_06(Jan) 1/27/06 4:39 PM Page 31

Electricity Today32

Nodal is expected to create long-termincentives for relieving the congestionproblem through the appropriate locationof new generation and transmissionresources. The PUCT has also expressedits expectation that Nodal pricing willprovide incentives for increased load par-ticipation in the market:

The rule is expected to yield impor-tant benefits, such as a reduction in localcongestion costs; reduced opportunitiesfor gaming and manipulation in thewholesale electricity market; increasedprice transparency and liquidity in thewholesale electricity day-ahead energymarket; increased locational price trans-parency for resources; more efficient andtransparent dispatch of resources in real-time; improved siting of new resources;and a reduction in the amount of newtransmission facilities needed to supportthe reliability of, and competition in, thewholesale electricity market. These ben-efits will provide participants in thewholesale and retail markets with moreaccurate wholesale prices, which willfacilitate better-informed price responsesby customers in those markets. Moreaccurate pricing will lead to more effi-cient consumption decisions by end-usecustomers, and the rule may lead tolarge-scale deployment of advanceddemand-response technologies and dis-tributed generation resources, moresophisticated services, and increased effi-ciency in the consumption of electricity.

For these benefits to be realized, thestate must also develop a viable strategyfor the deployment of advanced electron-ic meters.

Transmission line congestion is aparticular problem in various parts of theDallas–Fort Worth Metroplex, whereshort-term blackouts and brownouts arecommon. The Dallas-area ERCOT con-trol zone was responsible for roughlyhalf of all uplifted local congestioncharges in 2003 — approximately $160million. The DFW area imports 65 per-cent of its power, and decreasing thatnumber could exacerbate the region’schallenge to reduce nitrous oxide emis-sions in order to meet its Clean Air Actgoals. The locally-generated electricitycomes from the state’s oldest fleet ofgeneration plants, many of which are log-ical candidates for retrofit or retirementas a way to curtail emissions. However,ERCOT has concluded that if a signifi-

cant amount of the local power becomesunavailable, the existing transmissioncapability into the DFW area will beinadequate to allow imported power toreplace it. Even with several new trans-mission projects underway, “it appearsthat much more transmission capacitywill be needed” to avoid problems ofsupply inadequacy and voltage instabili-ty.

THE ROLE OF DEMANDPARTICIPATION

Demand-side resources are a poten-tially powerful part of the new market’sability to address these challenges. Bypromoting a culture of awareness of thevarying cost of electricity, demand par-ticipation promotes overall energy effi-ciency, typically resulting in per capitaenergy use reductions. And because effi-

cient load management and distributedgeneration are an alternative means toreduce transmission and distribution sys-tem congestion, it reduces the need forthe construction of new high-voltagepower lines in populated areas that areresistant to them. Demand participationcontributes to a cleaner environment byreducing the need to bring peaking plantsonline and delaying the need to build newspeculative power plants.

Prior to restructuring, utilities wereassigned demand response obligations bythe Public Utility Commission of Texas(PUCT), and met them with a system ofspecial tariffs for large industrial cus-tomers that were able to interrupt load onshort notice. In the restructured environ-ment, market participants are expected torespond to free market forces to fill thevoid left by this loss of regulatory power.The task of replacing the interruptiblerate system with market-based programsfor most of Texas has fallen to ERCOT,the independent system operator that

oversees more than 85 percent of thestatewide grid. The PUCT applied someurgency to the importance of load partic-ipation and price responsiveness in thenew market, with this part of its June2001 Final Order approving variousERCOT Protocols:

ERCOT shall develop additionalmeasures and refine existing measures, toenable load resources a greater opportu-nity to participate in the ERCOT mar-kets. As many of these measures as pos-sible should take effect by January 1,2002, because existing Commission-approved tariffs addressing load resourceparticipation in the markets will expirethis year.

ERCOT’s board of directors andcommittee structure is prominently com-posed of generation companies and otherentities with roots in the regulated utilityworld, and the development process forits protocols has been dominated by theseentities. The result thus far is a wholesaleelectricity market that is not well suitedto demand participation. Low commodi-ty prices and the surplus of available gen-eration have temporarily eroded marketincentives for demand response, and thenet result has been a decline in demandresponse capacity in Texas since restruc-turing.

To meet its obligations under thePUCT mandate, ERCOT has turned to itsstakeholder-based Demand-Side Work-ing Group (DSWG). The group hasdeveloped protocols for the new loadreduction programs, known as Load Act-ing as a Resource (LaaR) and BalancingUp Load (BUL). Both focus primarily onfacilitating payments to large industrialcustomers who agree to interrupt theirservice from the grid, sometimes byreplacing it with on-site generation

The LaaR program, launched in2002, allows industrial loads to partici-pate in the ERCOT wholesale capacitymarkets, and has proven successful. Cur-tailable load resources may comprise upto 50% of all capacity resources in theResponsive Reserves market, and numer-ous industrial customers — many ofthem former interruptible tariff cus-tomers who could take advantage ofalready-installed equipment — are bid-ding into the market regularly.

Although this provides less capacitytoday than prior to restructuring, marketparticipants believe the availableresources have noticeably suppressedaverage prices in the ResponsiveReserves market.

Texascontinued from page 31

ET_1_06(Jan) 1/27/06 4:40 PM Page 32

smaller price spikes, and reduced market power by generators.When supplies are tight, small changes in the amount of powerdemanded can have a dramatic effect on market clearingprices…. “MOD believes that the Commission needs to be thecatalyst on this issue. MOD would welcome encouragementfrom the Commissioners’ offices to assign more importance tothis issue and spur stakeholders to implement changes that willincrease price responsiveness for the demand for electrici-ty….”

Echoing this concern, a consultant’s report for MOD, pre-sented to the Commission in October 2002, recommendednumerous improvements in the ERCOT markets to encouragedemand participation, primarily for improving the perfor-mance of the BUL and LaaR programs.

ERCOT’s load reduction programs cater to large industri-al customers, in part because these customers are large enoughto exert influence individually, or sophisticated enough todevelop a network to aggregate their loads. A differentapproach will be required to involve residential and smallcommercial customers — representing over 99 percent of thecustomer base, up to two-thirds of the overall load, and a dis-proportionately higher share of the peak load. Although theirvehicles for participating are quite different, residential cus-tomers have been shown to have a similar or even proportion-ately greater capacity for responding to price signals com-pared to large industrials. Even if system limitations preclude

The BUL program was devised as a way for other loads,primarily industrial but also including aggregated load pro-grams such as Direct Load Control (DLC), to bid into the Bal-ancing Energy market when prices are high due to scarcity ofsupply. After numerous delays, the BUL program was finallyreadied by ERCOT in late 2003, but to date has yet to see acustomer registered. DSWG members attribute the slow startfor BUL to a provision in ERCOT’s administration of the pro-gram that could penalize customers for another customer’sfailure to perform.

In theory at least, DLC programs are eligible to be reim-bursed by the market for load curtailments irrespective ofBUL. ERCOT working groups have written protocols toenable REPs to assign settlement profiles to customers in DLCprograms. These may include group residential programs inwhich controlled load reductions are enabled through smartthermostats or switches on air-conditioners or water heaters.To date, however, no such small customer programs haveentered the competitive market. Many REPs have attributedthis lack of success to the continuing burdens of executing thenew market requirements, and to the overall challenge ofbuilding a business case for a mass market program in Texas’scompetitive choice market. Under the ERCOT market struc-ture, third-party DLC providers cannot participate without thecollaboration of a REP. Thus, DLC providers encounter manyof the same barriers to entry as advanced metering providers.

Indeed, more than two years after the opening of the mar-ket, the role of smaller consumers has yet to be addressed indetail. The ambition behind the following language from theDemand Side Working Group’s original recommendations tothe PUCT in 2001 remains unfulfilled:

• “Identify other opportunities to enhance the responsive-ness of customers to wholesale price changes through betterprice signals, better metering, behind-the-meter renewableenergy projects, distributed generation, consumer education,and other means.

• “Identify impediments to the participation of smallerloads in ERCOT’s markets.

This could include a review of ERCOT’s load profilingprocedures, the communication of market prices to consumers,outreach efforts, and “behind-the-meter” technologies thatfacilitate consumer response or clip peaks.

• “Coordinate with pending PUCT rulemaking proceed-ings that are exploring metering and time-of-use rate issues.”

THE IMPORTANCE OFPRICE SIGNALS

Improvements in demand elasticity occur only when themarket begins to break down the historic disconnect betweenwholesale and retail prices. This will require a transition fromthe near-universal dominance of flat-rate pricing of electricity,in which prices are the same regardless of when the power isconsumed. REPs realize that DLC, demand response, andenergy efficiency are alternatives for electricity supply, andprovide demand response service for customers. Smaller cus-tomers can increase the market’s demand elasticity factor onlyif their retail rates begin to reflect the cyclical and seasonalfluctuations of the wholesale market. The senior staff of thePUCT’s Market Oversight Division (MOD) has focused onthis issue, as illustrated by this section of a memorandum to thecommissioners:

“If retail customers modify their usage in response toprices in the future, ERCOT will see reduced price volatility,

33January 2006

Continued on Page 35

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ET_1_06(Jan) 1/27/06 4:40 PM Page 33

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ET_1_06(Jan) 1/27/06 4:40 PM Page 34

not dependent on AMR sys-tems, as some TOU metersmay be read by walk-up meterreaders using hand-held elec-tronic devices.

Most advanced meterstoday are modular, providingscalability and versatility forcustomers, electricityproviders, and meter readingentities. Depending on the ser-vice area (terrain, customerdensity, building type, etc.) and the number of featuresrequired, the product price of advanced meters, especiallythose suited for smaller-demand customers, has dropped inrecent years to less than $100 for new meters, and even less toretrofit electromechanical meters.

The value of a kilowatt-hour is greater at peak than off-peak. Thus, the difference between demand participation andtraditional energy conservation or energy efficiency is that theenergy use reductions are targeted to specific periods of time.California’s problems occurred in spite of the nation’s lowestresidential per capita use of electricity, according to the Con-gressional Budget Office (CBO), which found that the statefailed to address demand response among smaller customersbecause they lacked the enabling technology, beginning with

them from participating directly in the wholesale markets, theycan exert more control over their own energy costs — and thusincrease demand elasticity —through programs involvingtime-sensitive electricity rates.

ADVANCED METERS: THE ENABLING TECHNOLOGYFor 99-plus percent of Texas customers, electricity con-

sumption is measured through a single monthly reading ofkilowatt-hours (peak demand is also recorded for commercialcustomers with over 10kW of demand). The meters measuregross consumption without regard to when the energy was con-sumed.

In recent years, the meter industry, mirroring the broadertechnology explosion, has produced increasingly powerful andaffordable new products. Already in use by many large com-mercial and industrial customers in Texas, and by smaller cus-tomers in other markets, advanced meters offer a criticalupgrade from traditional meters: they produce more detailedusage data by measuring energy consumption in intervals ortime blocks. This feature enables customers to view and man-age their usage during critical peak periods, and is necessaryfor electricity providers to offer time-sensitive pricing options.(Depending on the customer and the meter functionality, pric-ing plans may include sophisticated real-time pricing (RTP) inwhich (typically larger) customers pay rates that track whole-sale market prices, or more simple time-of-use (TOU) rateplans that enable customers to save money by shifting someconsumption to lower-priced periods of the day that are estab-lished in advance. Other rate plans include “critical peak” or“call option” packages that reward commercial customers oraggregations of smaller users for curtailing loads, typically on24 hours notice, during a few super-peak events per year. Otherplans combine TOU and critical peak by offering predictablebut variable rates for the vast majority of days, with theprovider retaining the ability to raise rates to critical peak lev-els for a certain number of hours per year.)

Another feature of the advanced meters available today isthe communications capacity.

Advanced meters almost always deliver the customer’sconsumption data to the meter-reading entity automaticallyand remotely through a secure communications network.

Automatic Meter Reading (AMR) — either fixed networkor “drive by” — has significantly reduced costs for many util-ity companies, and networked metering communications ser-vices can greatly enhance the value of demand participation bymaking the data available to providers and customers on atimely basis.

Certain types of AMR technology simply replace tradi-tional monthly walk-up meter reads with monthly automaticmeter reads, and many utilities have added AMR communica-tions to their meters without including a demand participationcomponent. Meters with an AMR component represent at least16.9% percent of U.S. electricity meters, with 32 percent of allU.S. utilities reporting at least some meters read through AMR.However, only 13% of utilities with AMR report using it fortime-of-use pricing. This suggests that for the mass market,many utilities have made successful business cases for AMRprimarily to reduce costs for their monthly kWh reads. Itshould also be noted that a demand participation component is

35January 2006

Texascontinued from page 33

Continued on Page 46

Most advanced meters todayare modular, providing scala-bility and versatility for cus-tomers, electricity providers,and meter reading entities.

ET_1_06(Jan) 1/27/06 4:40 PM Page 35

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37January 2006

The security of automated elec-tric transmission and distribu-tion (T&D) systems deliver-

ing power to industrial, commercial, andresidential users is critically important toensure continued and uninterrupted ser-vice of this vital resource. Electric utilityT&D systems link generating facilitieswith end users customers through a com-plex network of high voltage power linesand primary and secondary distributionsubstations.

Because of ever-increasing demandand limited generating capacities, effi-cient T&D of electricity is vitally impor-tant to adequately fulfill user needs andfuel the economic engines of countriesaround the globe. Because T&D systemsare monitored and controlled throughmostly electronic means from remotelocations, protecting these assets againstpotential cyber attacks is criticallyimportant to ensure their continued avail-ability in today’s heightened security cli-mate.

This article examines specificaspects of existing T&D systems that arevulnerable to cyber attack and addresseshow these can be effectively protected toimprove their security and mitigate risks.

T&D systems dispense electricpower from their generating sources tothe end users by distributing and convert-ing electricity from high-voltage levelsused to convey power over large dis-tances to voltages that can be safely usedby end customers. In doing so, the sys-tems employ Supervisory Control andData Acquisition (SCADA) mechanismsto monitor and control the supply of elec-tricity to meet the specific customerdemands.

SCADA mechanisms connect opera-tors at centralized monitoring and controlcenters with substations where distribu-tion grids are activated and where trans-formers are brought on line to step downhigh voltage feeds for subsequent local-ized distribution and consumption.

SCADA systems reduce labour costs andallow system-wide monitoring andremote control of field sites and devicesusing specific communications proto-cols.

To enable this functionality, central-ized control centers connect directly withRemote Terminal Units (RTUs) andIntelligent Electronic Devices (IEDs)which are directly linked by local wiringto the transformers and switches that dis-tribute power according to demand fluc-tuations. Communications betweenSCADA master control centers and asso-ciated RTU/IEDs are vulnerable to inter-ception and alteration. In addition,remote access and maintenance ofRTU/IEDs by field technicians is also acritical security aspect.

A schematic representation of theinteraction between centralized controlcenters, remote maintenance access, andsubstations equipment is shown in thefigure shown above:

Because alteration of the data thesemechanisms report and the control sig-nals these are given by operators can leadto severe operational disruptions, these

systems must be protected against unau-thorized access, and the information tra-versing these secured to ensure itsintegrity and confidentiality.

SCADA systems have been in placefor over 40 years and were originallydesigned and installed at a time whenthere was little concern for communica-tion security. The systems have a typicaloperational life cycle in the order of 15 to30 years, and with the recent focus onsecurity, will take significant time tofully transition to a completely securesystem.

Improving the security of legacySCADA systems against cyber attackrequires flexible security solutions thatare easy to install and do not impact sys-tem performance and operations.

To address the security needs of theelectric industry, the North AmericanElectric Reliability Council (NERC) isdeveloping a Critical Infrastructure Pro-tection (CIP) standard to provide guide-lines on the establishment of securitypolicies and procedures, including cyber

SCADA

SECURITY IN AUTOMATED T&D SYSTEMS,AUTHORIZATION, AUTHENTICATION, INTEGRITY

AND CONFIDENTIALITYBy Juan C. Asenjo, CISSP

Continued on Page 39

ET_1_06(Jan) 1/27/06 4:44 PM Page 37

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nications from 300bps to 115.2Kbps and is designed to meetemerging industry regulations and standards such as thosebeing developed by NERC. The retrofit security solution usesthe Advanced Encryption Standard (AES) to protect theintegrity and confidentiality of data as well as to secure user-access control.

Unprotected SCADA mechanisms are vulnerable to cyberattack. Interception, alteration, and replay of data exchangedby these can allow an intruder to effectively seize control of autility’s T&D system. Improving the security of these systemsrequires flexible solutions that are easy to installation, simpleand transparent to operate, and have no impact on operationalperformance.

Because SCADA mechanisms have typical useful lives ofover 15 years, retrofit solutions address immediate securityconcerns. Authentication and encryption of communicationslinks between master control centers and fielded RTUs andIEDs and secure remote access to maintenance ports are keyelements of a comprehensive strategy to enhance cyber secu-rity of T&D systems.

Mr. Asenjo has over 20 years experience in the informationsecurity field, formerly with the National Security Agency, andmost recently with Thales’product development and marketingdepartments. He has degrees in Engineering, Business, and isa Certified Information System Security Professional.

security. The deployment of retrofit security solutions can pro-vide significant advantage when looking to overhaul the secu-rity posture of T&D systems in place today and enable fieldedsystems to be brought into compliance while embedded secu-rity features are designed and made available to the market aspart of future more robust SCADA systems.

The specific security requirements of electric T&D sys-tems and their respective SCADA mechanisms include protec-tion for authentication to ensure that correct users and devicesare connected, integrity to ensure correct feedback and com-mands are received and issued, and confidentiality to preventinterception and play back. Remote access maintenance is alsoa vulnerable aspect of SCADA mechanisms. As these permitentry into field substation devices by maintenance techniciansthrough dial-up connections with little or no authentication,role based access control is critically important.

In the following paragraphs, each of these aspects, includ-ing SCADA circuit protection, modes of operation and remoteaccess security are examined in further detail.

SCADA circuit protection typically refers to point-to-point applications connecting SCADA master control centersto remote RTUs and IEDs in the field. SCADA communica-tions typically operate at low speeds in the order of 300bps to9,600bps. Communication links normally used for these appli-cations include; dial-up phone, leased line, spread spectrumradio over asynchronous connections, or routed networks.

When these circuits are deployed in point-to-point scenar-ios, the connection between the SCADA master and remoteRTUs require only a discrete one-to-one security schemeallowing the use of a simple link encryption device. Multi-dropscenarios where the SCADA master control is connected tomultiple RTUs in the field are more complex and require apoint-to-multi-point encryption scheme that, using the com-munications protocol employed such as MODBUS or DNP,can create specific protected tunnels between the various field-ed devices and the control center.

An additional configuration commonly found in manynetwork infrastructures is the mixed-mode scenario where notall connections to remote RTUs and IEDs need to be secured.In these configurations, two or more RTUs downstream in thenetwork may be configured with multiple addresses forencryption or clear operation. Mixed-mode environment willbe commonly found in SCADA networks that are in theprocess of being transitioned to secured operation, and supportfor this application will provides tremendous flexibility asencryption solutions can be added as required and in accor-dance with established security policies and priorities.

As government pressure continues to build to secure criti-cal infrastructure assets against cyber attack, and as industryorganizations such as NERC finalize specific standards andrecommendations dictating how to secure deployed SCADAsystems, retrofit commercial solutions with the characteristicsoutlined in this article will begin to enter this niche market.

One such product, the Datacryptor SA, offers NationalInstituted of Standards and Technology (NIST)-approved cryp-tography for authentication and encryption of SCADA con-nections and maintenance port access, and offers protection ofSCADA networks and remote access to field devices (RTUsand IEDs). The solution supports serial asynchronous commu-

39January 2006

SCADAcontinued from page 37

ET_1_06(Jan) 1/27/06 4:48 PM Page 39

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43January 2006

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Electricity Today46

advanced meters. “(These customers)have acquired few devices that would letthem reduce electricity use on shortnotice, such as real-time meters (whichwould tell them when prices were chang-ing),” according to the CBO. “Successfulrestructuring may necessitate that resi-dential and commercial customersacquire many of the same demand-man-agement capabilities that industrial con-sumers have.”

NEW PRODUCTS, SERVICES &TECHNOLOGIES:

THE PROMISE OF DEREGULATIONGiven adequate incentives, small

customers can save money and increasedemand elasticity by rescheduling thenon-essential functions of energy-inten-sive appliances such as clothes washersand dryers, water heaters, dishwashers,and pool pumps. Further, price signalsalter the economics for acquiring manyother innovative products and servicesfor focused energy efficiency, including:

• Software applications that allowcustomers to retrieve energy use data viaInternet or closed network. One poll dis-

covered that 62 percent of residentialcustomers said they were interested inviewing their energy usage on the Inter-net;

• Energy-saving technologies suchas programmable “smart” thermostats,timers, remote-controlled switches, anddevices that cycle or curtail high-con-sumption appliances during peak useperiods - either automatically or as theresult of signals delivered by the utilityor the consumer; and

• The burgeoning technologies of“smart home” gateway management sys-tems that feature robust energy-savingtools as a major component of home andbusiness management platforms.

• Energy storage technologies suchas thermal storage, battery storage,photo-voltaics, fuel cells, etc.

Especially if combined with theseand other types of automation technolo-gies, load shifts that result in meaningfuldemand elasticity require only modestchanges in behavior and little or no sacri-fice of convenience.

Most advanced meters may be read-ily configured for bi-directional netmetering; the function that permits cus-tomers to sell qualifying self-generatedpower back to their provider. In Texas,

net metering rules were passed in 1986 inan effort to encourage smaller customers(under 50kW in demand) to installrenewable resources such as rooftopsolar panels. The rules will require clari-fication in the new market, where com-petitive REPs have replaced the verticalutilities as the electricity providers. Com-bining net metering with time-sensitivepricing could further enhance the valueand return on investment of small-scaleclean energy sources by providingstronger incentives to consumers to off-set the costs of peak power.

Advanced meters can thus enhancedemand participation capabilitiesthrough peak load management, energyefficiency, and distributed generation.They offer the prospect of faster returnon investments and the opening of newmarkets for promising energy manage-ment products and services. FormerPUCT Commissioner Perlman suggestedthat pursuing more advanced meteringcapabilities will help Texas to become a“center of innovation in energy technolo-gies”. Viewed this way, advanced meterscan be seen as a driver of economicdevelopment and the catalyst for a trans-formation of retail electric competition.

ADVERTISERS INDEX - January, 2006

ADVERTISER PAGE CONTACT INFO ELECTRICITYFORUM WEB PAGEAGO 11 www.arcfr.netAccess Control Sales 45 www.accesscontrolsales.com www.electricityforum.com/products/access.htmComverge 5 www.comverge.comCIS 21 www.cisweek.orgCUEE 44 www.cuee.caDoble 36 www.doble.comDuPont 7 www.dupont.ca www.electricityforum.com/products/dupont.htmFinepoint 34 www.circuitbreakerconference.comFLIR Systems Ltd. 43, 45, 48 www.flir.com www.electricityforum.com/products/flir.htmGITA 40 www.gita.orgHubbell Power Systems 2, 33, 45 infoHPS@Hubbellonline.com www.electricityforum.com/products/hubbell.htmIEEE/PES T&D EXPO 41 www.ieeet-d.orgIPC Resistors 9 www.i-gard.comIRIS Power Engineering Inc. 19 www.irispower.com/ www.electricityforum.com/products/iris.htmLineal 26 www.lineal.com Lizco Sales 45 www.lizcosales.com www.electricityforum.com/products/lizco.htmMagna Electric Corp. 17 www.magnaelectric.com www.electricityforum.com/products/magna.htmMegger 29 www.megger.com www.electricityforum.com/products/avo.htmMetering America 38 www.metering.comMidas Metering Services 39 www.midasmetering .comMikron Infrared Inc. 47 www.mikroninfrared.com www.electricityforum.com/products/Mikron_Infrared_Inc.htmlMTE Corporation 31 www.mtecorp.com www.electricityforum.com/products/mte.htmNETA 42 www.netaworld.orgNRG Stream 35 www.nrgstream.comNynas 15 www.nynas.comOptimized Devices Inc. 45 www.optdev.com www.electricityforum.com/products/optimized_devices.htmUndrground Devices. 27 www.udevices.com www.electricityforum.com/products/underground.htmUnifin International 23 www.unifin.comThe VON Corporation 25 www.voncorp.com www.electricityforum.com/products/von.htmWeidmann Electrical Technology 13 www.actiinc.com www.electricityforum.com/products/weidmann.htm

Texascontinued from page 35

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