asset management

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www.energycentral.com EnErgyBiz magazinE 43

ReaD RegULaRLY UPDateD InFORmatIOn aBOUt Asset MAnAgeMent: www.eneRgYcentRaL.cOm/am.cFm

Don’t Forget the PastPG&E Looks to Curb DEmanD

Asset management is very much on the mind of Mark Alexander, manager of Pacific Gas & Electric’s

demand response department. Alexander reports on how he daily wrestles with new challenges to

run utility assets at peak efficiency to help meet new state mandates.

ENERGYBIZ What are the newest, most exciting trends in asset management at PG&E?alexander “Don’t throw the past away. You might need it some rainy day. Dreams can come true

again when everything old is new again.” Those Peter Allen song lyrics ring true today when it comes to everything from high fashion to retro car design including “new” trends in utility asset management.

Demand-side management (DSM) has been around since the 1970s. In the ’70s, the emphasis was on energy conservation. In the early ’80s when capacity was in short supply, load-management programs were implemented. In the early ’80s, integrated resource planning was the hot topic; however, as capacity became available by mid-decade, many load-management programs were shut down. In the early ’90s, PG&E experimented with DSM as an asset-management tool in an innova-tive pilot project called the Delta Project where the concept of concentrated DSM could enhance utility distribution system assets. The latter ’90s were spent preparing for deregulation and customer choice. DSM chugged along at a slow simmer until the energy crisis, which rekindled a strong desire for demand-side programs that helped customers control rising bills and protected customers from possible rotating outages.

Asset Management

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44 EnErgyBiz magazinE July/August 2007

Today, there is universal recognition that DSM has a significant role to play in managing utility assets. Utility management and regulators at the state and federal levels recognize the value of being able to deploy customer DSM programs that better utilize existing infrastructure rather than building new, large-scale infrastructure that is only required to meet peak demands for only a few hours annually.

Another exciting trend is PG&E’s deployment of an advanced metering infrastructure, which offers great potential to enable customers to receive more detailed and timely information about energy usage and energy pricing. This knowledge will enable cus-tomers to better manage their own energy usage and participate in grid-friendly programs that help asset utilization.

Finally, the advancements in technology and automation beyond the revenue meter available to customers will help them manage energy use as well as participate in voluntary demand response programs. PG&E’s technical assistance program offers engineering assistance to identify demand response potential, and the technology incentive program offers cash incentives for instal-lation of recommended enabling technologies. These technologies are capable of receiving program or pricing signals from PG&E and automatically triggering predetermined load-management strategies without further human intervention.

ENERGYBIZ How helpful are vendors in helping PG&E achieve its asset management goals?alexander Vendors play an integral role in helping PG&E

achieve its asset management goals where technology — and automation-based solutions are required.

ENERGYBIZ Where is asset management headed at utilities? alexander A trend toward the use of customer-side solutions

with traditional utility asset management continues. In California, state energy policy as defined in the Energy Action Plan sets a “loading order” where all cost-effective, customer-side solutions are utilized prior to procuring traditional supply alternatives. Dependence on technology and automation to support customer programs also will increase, such as building-control software and energy-management systems that receive program or pricing signals and that adjust customer loads according to predetermined strategies.

ENERGYBIZ PG&E is hoping to better utilize its assets by controlling peak demand. One new program is expected to cut demand by 5 megawatts starting this July. How will it work? alexander PG&E’s new SmartAC program is part of our rich

portfolio of voluntary demand response programs offered to custom-ers and is a simple, highly effective way to manage the widespread demand for energy in the summer. SmartAC is a direct control, demand response program targeted at residential and small commercial cus-tomers’ air-conditioning equipment. In a program we are launching this year, 5,000 devices will be installed by July, with the ultimate objective of having 300 megawatts of load control in place by 2010.

The control-device technologies utilized are Cannon Technologies switches or programmable communicating thermo-stats. PG&E offers customers a choice between switches and thermostats. Switches will follow a cycling strategy up to a level as high as 50 percent; thermostat set points will be raised as much as 4 degrees during events. Events will be initiated during periods of grid distress or high prices initiated by the California Independent System Operator or in case of local emergency. Events will take place May through October and will be limited to no longer than 6 hours per day and as long as 100 hours per season.

Participating customers will remain comfortable during events because SmartAC technology adjusts air conditioners intermit-tently over several hours during the day and only when necessary. This small adjustment, multiplied by hundreds of thousands of air conditioners, can make a huge difference in energy consumption for the state and provide a healthier environment for everyone.

ENERGYBIZ I understand that peak savings will grow to 300 megawatts by 2010. What is the long-term potential of such technology? alexander The long-term outlook for the technology is excel-

lent because the hardware PG&E has chosen is at the forefront of demand response technology, and it has proven to be reliable with deployments by utilities across North America. The system that we are deploying offers operational flexibility, including the ability to work in conjunction with our advanced metering infrastructure as well as provide under-voltage and under-fre-quency protection to the grid. We expect that the system we are deploying will provide many years of benefits to PG&E and our customers. PG&E will continue to survey and evaluate the marketplace for technologies that best meet our needs and those of our customers.

ENERGYBIZ What would you like to see the vendor community provide in products and services not currently available? alexander We would like to see a move to more open

architecture in end-use control devices.

Log on today for a free subscription to Energy Currents newsletter at www.esri.com/energycurrents. www.esri.com/electricgas

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ties are asset-intensive organizations, and those assets are widely

dispersed geographically. Traditionally, lists, maps and the memo-

ries of highly experienced workers accomplished the tracking of

those assets. The system that evolved over the years wasn’t espe-

cially accurate, but it was “close enough for government work.”

Modern computer systems with enterprise resource plan-

ning, enterprise asset management, supply chain management,

geographic information system and other software have enabled

many – but not all – utilities to begin to get a more structured and

organized handle on the issue. However, just as they thought they

were about to solve the problem, it suddenly has become more

complex than ever. In fact, it has become “real-time” with all the

massive data collection, storage and analysis that entails. Real-

time data collection and analysis requires the development of the

next generation of utility asset management systems. Despite an

immediate need for the next-generation systems, they are only

beginning to be deployed.

The reasons why asset tracking and management at utilities

must evolve rapidly are clear, and the writing is already engraved

on the wall.

The reasons include the following:

» North American Reliability Corp. (NERC) Critical Infrastructure

Protection (CIP) standards have been given the force of law by

the Federal Energy Regulatory Commission. They require the

close tracking and monitoring of critical cyber-assets at a level

that never has been attempted before. These assets include not

only traditional information technology assets, but also super-

visory control and data acquisition, and intelligent electronic

devices on the grid. These new regulations are extensive and are

backed by audits that threaten fines as high as $1 million per

day for utilities found to be out of complaince. Tracking all these

assets and monitoring them in real time will be required, begin-

ning this year, despite the fact that the tools and procedures to

do so remain under development.

» Automated metering infrastructure/meter data management

(AMI/MDM) is required in California. Other states are likely to

follow suit after the energy act of 2005 put pressure on state

regulators to show why their utilities should develop AMI/MDM

and offer time-of-use electric rates. AMI envisions two-way

communications beyond the meter into homes and a massive

scale to enable demand response and other techniques to

reduce electric demand. The problem is that real-time commu-

nications with millions of homes and devices within those

homes will generate quantities of data and asset-intensive

investment that have only begun to be defined, much less

accounted for and analyzed.

» The intelligent grid and intelligent utility enterprise idea is

under development at a number of utilities and envisioned by

many others. This idea will continue to increase the number of

sophisticated control devices placed on the grid, requiring real-

time monitoring, control and tracking and generating massive

amounts of data.

» Distributed generation will continue to grow in importance

and complexity. Already, according to surveys by Sierra Energy

Group, the research and analysis division of Energy Central,

82 percent of investor-owned utilities, 69 percent of municipal

utilities and 50 percent of cooperative utilities report having

non-utility-owned generation connected to their distribution

– not transmission – grids. Even though utilities don’t own

many of these assets, which range from wind and solar power

to micro-turbines, trash-burning facilities and tidal power, their

connections and interactions with the grid still must be tracked

and accounted for.

» Demand response is a revival of the old demand-side manage-

ment idea in which reduced demand and consumption is treated

as an “asset” to the system financially and otherwise. This

esoteric idea of avoided generation as an “asset” also must be

monitored and tracked in real time.

» Green energy is being promoted as a result of tremendous

regulatory and legislative pressure. At present, only about

Next-generation Asset ManagementLEaDErs WiLL nEED rEaL-timE Data

by WarrEn b. CausEyTracking and accounting for assets has been a complex issue as long as there have been utilities. Utili-

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2.3 percent of all U.S. electric power is generated by nontradi-

tional sources, other than hydroelectric dams. However, despite

very real scientific and technological limitations on how fast

that percentage can grow, many states and localities already

are making demands that utilities meet artificially developed

standards for much higher percentages. No one is aware at

the moment of where all this increased green power is going to

come from, but the effort must be tracked and accounted for as

an “asset,” albeit a highly expensive one.

» Carbon caps are just around the corner. Once trading in carbon

caps begins, it would have to be tracked in real time. Coal-fired

plants – still representing 50 percent of U.S. electric generation

– will become much more expensive assets, and all this must be

balanced, in real time.

As one prominent chief information officer said recently,

everything seems to be reaching a “tipping point” at about the

same time. This does not mean that science and technology have

caught up with all these demands. In fact, most careful observers

believe many of these regulatory and legislative requirements to be

impossible to meet within the next 10 to 20 years, or even longer.

However, the tipping point is that regulators, legislators and politi-

cians are going to require them whether or not it is realistic to do

so. The tipping point is political, not economic, scientific or tech-

nological. In other words, the political movement has tipped over

to “irresistible,” and utilities are going to have to deal with it one

way or another.

Asset-management computer systems originally were devel-

oped to track “hard” devices, such as meters, transformers,

switches and substation devices. These early asset-management

systems then were linked to supply-chain systems for the purpose

of ordering and replacing assets as they were expended or placed

into service from inventory. Later, the idea of showing the location

of these devices in the field – through GIS systems – came along,

and asset management was linked to GIS. Asset management also

was linked to customer-information systems to show what assets

were located at which customer premises. Such systems gradually

replaced the old paper maps, lists, and memories of experienced

field crew members who could tell you which pole they attached a

device to, even if the list and map didn’t exactly show that place-

ment. But none of this was “real-time.” As the systems evolved,

some utilities were months and even years behind in updating

systems and accurately tracking and accounting for assets.

However, with all the demands being placed on utilities today,

such a haphazard, gradual process no longer will suffice. Utilities

must track everything in real time if they are to have any hope of

meeting the new demands.

Austin Energy is heavily into AMI/MDM and other aspects

of the intelligent grid. Austin’s chief information officer, Andres

Carvallo, is active in promoting the idea of utilities moving to the

next generation of asset tracking. “We publish KPIs (key perfor-

mance indicators) to our customers every quarter, and we track

those KPIs on a daily basis from number of incidents and calls and

problems solved to up-time, down-time, capacity projects, code

written — you name it, we track it,” he said.

While Austin Energy is beginning to get a handle on the integra-

tion of the grid with the enterprise and tracking real-time assets,

this process remains under development at other utilities.

The real-time world of the future will require extensive

“...up-time, down-time,

capacity projects...you

name it, we track it.”


1-888-333-2938


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analytics to determine exactly what happening and how these

dynamic forces can be dealt with to ensure utility survivability,

much less profitability – in the case of those that must show a

profit to shareholders – or at least break-even financial results for

municipals and co-ops.

Linking information technology assets to grid assets and

providing the analytics to deal with massive amounts of real-time

data so that all assets can be “tuned” to meet the regulatory, legis-

lative and business demands remains in the future, even though

decision-makers recognize the immediate need.

Success will require new levels of leadership, and the new

leaders must be enabled by comprehensive analytics – including

asset analysis – and decision-support systems.

In the future, an asset-management system that tracks

“things,” generates reports and issues work orders will not be

sufficient. A future system must be able to apply analytics to

massive amounts data on a real-time or a near-real-time basis to

assist leadership in making critical decisions in an environment that

already has “tipped over” to a totally different world.

Executives at major asset-management vendors say they

see the same issues and are working to develop systems that can

handle the problem. Henry Bailey, the utility industry principal at

SAP America, Newtown Square, Pa., said, “It is a constantly moving

target. The analytics are never going to be complete. What will be

necessary in the future is the ability to modify the tools to adjust

to new operating conditions. As you start learning information

about your utility, you start asking more questions, and you begin

to realize what you didn’t know, and you ask more questions. Real-

time information is going to be key to better asset management,

especially when you consider you’re installing small computers

almost in every kind of component going into the grid, power plants

or any part of their business. They’ll still have the wires and poles

without semiconductors, but a lot of the electronic components

already have sensors and programmable logic embedded in the

operation of the equipment.

“What SAP is doing,” Bailey continued, “is working on our

enterprise systems through our service oriented architecture. The

enterprise is where the real-time or near-real-time comes into play.

We’ve been seeing this need in all the industries we serve and espe-

cially utilities.”

At Oracle’s utilities global business unit, which absorbed

SPL WorldGroup in an acquisition last year, Guerry Waters, vice

president for industry strategy and marketing, said, “We see two

primary drivers for more real-time asset management. One is

AMI, which certainly gives more granular information about the

performance and operation of assets, coming from the customer

base, and then tied back into the distribution network. You can

get very detailed information about where loads are occurring

and fluctuations in voltages. The other is distribution manage-

ment – there are very many more communicating grid manage-

ment devices. Asset management has a very important play in all

this. It now has details on the devices themselves, how they are

performing, when they are close to failure and when they need

scheduled maintenance. All this can be rolled up if you have the

necessary connectivity and communications model, which most

utilities do today.

“Software vendors who have the ability to analyze and

perform or suggest actions, will be an important element of asset

management in the future,” Waters said.

Putting all this together to deal with the “tipping point” envi-

ronment in which utilities and vendors find themselves will lead to

the next generation of asset management systems.


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[ c a s e s t u d y ]

In the fall of 2006, utility vehicles loaded with new solid-state electric meters left warehouses across Florida and North Caro-lina, and returned with an assortment of old electromechanical meters and a record: more than 20,000 meters exchanged in a single day.

That record was set by Progress Energy during one of the fastest deployments in North American history. By the time the meter project was completed, more than 2.7 million meters were installed in only 18 months.

Progress Energy, based in Raleigh, N.C., is one of the nation’s 10 largest investor-owned electric utilities. In 2005, Progress Energy signed a contract with Itron to replace traditional elec-tromechanical residential meters with Itron’s CENTRON™ solid-state electricity meters, equipped with automated meter reading technology. The intent, says Luis Ordaz, project manager for Progress Energy, was to reduce meter costs, not set records.

“We had an aggressive schedule to deploy several million meters in Florida, North Carolina and South Carolina in only 20 months,” Ordaz said. “Obviously, to make this work, communica-tion was critical to gaining acceptance of this change in technol-ogy — internal with our staff and partners, and external with our customers.”

Don Welte, vice president of Itron field operations, said the company shipped, on average, 60,000 to 70,000 meters per week to Progress Energy. In 2006, Itron shipped six million meters for the year to customers.

“Two million of those meters went to one utility — Progress Energy — so that one out of every three meters we shipped last year went to the Progress project,” said Welte. “That is some-thing that has never happened in the history of our company.”

Three shifts were operating at the Itron factor in West Union, S.C. to meet the demand. The manufacturing plant worked around the clock to make it happen.

To get an idea of how many meters were installed, imagine 775 Sears Towers stacked on top of each other reaching skyward — that is what 2.7 million meters would look like.

Louis Santilli, former project manager for the Progress Energy metering deployment, says the success of the project was in picking a good partner who can act rapidly and help coordinate project management, meter manufacturing and installation. In addition, both the utility and vendor need to have strong organi-zational support and autonomy.

Each partner needs to expect the unexpected and be prepared with contingency plans. Santilli said only three days of productiv-ity were lost due to poor weather, and the project successfully completed 99.75 percent of the planned installations.

To ensure quality of meters and mobile data collectors to meet the accelerated deployment, constant meter testing, production audits and quality control measures were executed throughout the project. Shared data and weekly project status updates kept the deployment team informed and on track, said Bob Donaldson, who managed the Carolinas deployment for Progress Energy.

Lessons Learned

The lessons learned from such a rapid deployment are transferable to other projects. The most notable contributors to the success of Progress Energy’s Mobile Meter Reading project included:• Careful upfront planning• An experience project team• A turnkey contract• Communication, flexibility and attention to operational details• Close monitoring of business case metrics

“Speed, without attention to customer service, safety and cost is of limited value,” Donaldson said. “Throughout the deployment, Progress Energy maintained its core values of safety, customer service and financial responsibility.”

Current Benefits of MoBiLe aMr

Progress Energy is on track to save about $21 million per year with the use of AMR technology due to reduced operating and maintenance costs. Staff reductions include eliminating 200 contract positions in the Carolinas and 160 positions in Florida. With the increased accu-racy of solid-state meters, a 50 percent reduction in meter related billing exceptions, such as work order errors, also has been realized.

Ordaz said Progress Energy was able to reduce its meter reading fleet, saving vehicle costs and insurance. Employee safety increased as meter readers were no longer entering private property. In addition, improved meter accuracy resulted in an increase of revenue and tamper and theft cases have been reduced.

Progress Energy recently completed the second phase of the project, identifying accounts where a demand meter was in place, but the usage did not warrant it. The utility replaced about 34,000 meters in the Carolinas and 15,000 meters in Florida during this second phase of the project. Optimization of meter reading routes is currently underway.

ContaCt

Christina KellyMarketing/Communications(509) [email protected]

Progress energy’s accelerated aMr deployment: Commitment and Communication

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Making Wind FitbrEakthrouGhs PossibLE

by WiLLiam oPaLka

With increasing public demand for green energy and favorable tax policies in place at least through

the end of next year, wind energy’s upward draft shows no sign of

abating. In fact, in its first-quarter 2007 market report, the Amer-

ican Wind Energy Association projected another 3,000 megawatts

of capacity would be built this year, and thousands of megawatts

remain on the drawing board in the ensuing years.

Solutions to the traditional impediments to wind development

– intermittency and lack of transmission access – will continue to

be challenges, operationally and logistically. Some of the largest

players in wind-driven power generation – and smaller ones, too – are

creating ways to alleviate these concerns through a range of efforts,

from technical advances to massive capital expenditures.

The fact that wind doesn’t always blow when it’s needed, or

it blows at times when customers are using less electricity, has

impeded acceptance of wind-driven power generation for many

years. The variable output that accompanies strong gusts followed

by light breezes would create challenges for grid stability if wind

were to occupy a larger share of the electric generators’ portfolio,

and it will hamper its acceptance in many quarters. But with state

mandates to increase the amount of clean energy in the mix, inte-

grating wind is not merely desirable, it’s a requirement.

Proponents say the apparent shortcomings are not enough to

stifle continued growth. Managing the output plays a role, and so

does setting realistic expectations of what wind-driven generators

can provide to the electric grid.

Suitable transmission planning and operations will lead to greater

acceptance. That part of managing this asset is well under way in

many regions of the United States where wind energy is most abun-

dant. The common challenge is to move generation from areas where

it is most prolific, through the Great Plains and Midwest regions, to

load centers in large cities, often hundreds of miles distant.

In fact, the Holy Grail of the wind-power industry in America,

tapping the vast resource from North Dakota to Texas and effi-

ciently sending the energy to the load centers closer to the coasts

or to population centers in the nation’s midsection, already is tech-

nically feasible and is approaching economic viability.

To that end, AEP embarked on a decade-long, $7 billion build-out

unveiled in April before the Public Utility Commission of Texas in which

wind-driven power generation will play a significant part. Texas has

a well-known transmission-line bottleneck west of McCamey such

that power generated by wind in west Texas cannot always reach load

centers in the eastern sections of Texas – and this, in a state that is

becoming a leader in wind-driven power generation capacity.

An 11-state utility, AEP is a large purchaser of wind energy, and

to a lesser extent an owner and operator of some facilities. It has

2,200 megawatts of wind power on its transmission system in Texas

and Oklahoma. Mike Heycek, senior vice president for transmission

for the Columbus, Ohio-based utility, said one technical challenge has

been overcome. “Voltage support is required, and that is a problem

that is certainly solvable now,” he said. In fact, a 765-kilovolt line can

now sustain transmission into the hundreds of miles with significant

leakage. AEP even envisions wind generation from the central plains

as cost-effective and available as far east as Chicago.

Operationally, the integration of wind power is the subject of

ongoing efforts in the Pacific Northwest. The federal Bonneville

Power Administration (BPA) is participating in a “Northwest Wind

Integration Action Plan” along with many other stakeholders.

The collaborative process includes BPA, investor-owned utilities,

municipals, co-ops, environmental groups and others. This spring,

it released a framework to integrate wind power into the overall

power generation and distribution mix in the northwestern states.

A prolific hydropower generation capacity has been used to

advantage to smooth out the ups-and-downs of wind variability in

the Pacific Northwest. But hydropower generation in that region is

at its limit, and peaking generation is often produced in the same

way it is in the rest of the country: through expensive gas-fired

generation. The cost advantage of hydro is therefore lost.

The value of wind-drive power generation is not realized as

a capacity resource. Elliott Mainzer, manager of transmission

strategy and planning, said, “The primary value is displacing fossil

fuel generation and reducing the carbon footprint.” Wind power

fits into the generation portfolio when it helps to avoid the opera-

tion of expensive natural gas plants.

Meanwhile, associated operational costs may increase with a

higher degree of wind penetration into the overall portfolio mix. “In

general, the studies have found that wind integration costs are a


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significant, but not dominating portion of total wind resource costs,

up to wind nameplate penetration levels of 20 to 30 percent of peak

load.” BPA and the investor-owned utilities estimated the costs for

various service territories in the Northwest. In extreme cases, such

as the Avista and Idaho Power service territories, the costs can range

from $8 to $16 per megawatt-hour, on an hour-to-hour basis.

A remaining challenge is the size of the control area in which

the resources are located: the larger the area, the more readily

wind generation from geographically distant plants is integrated.

With 16 control areas served by BPA, coordination is essential to

lessen the costs associated with integrating wind. “Short of actual

control-area consolidation, the two most significant steps toward

realizing this benefit are the development of expanded wholesale

markets for control-area services and greater operating-area

revenue sharing.”

Studies in the United States and Canada have demonstrated

that thousands of megawatts of wind power can be accommodated

into the power grid with minimal disruption. GE Energy performed a

study in New York that showed the state could accommodate 3,300

megawatts of wind generation. “Wind farms would include state-

of-the art technology, with reactive power, voltage regulation and

low-voltage ride-through capabilities” that would maintain grid

stability, the report concluded. Similarly, a GE study for the Ontario

Power Authority found that there were minimal system operation

impacts for levels of wind capacity as high as 5,000 megawatts.

The system has no operational or physical constraints to

prevent 6,000 megawatts from being generated by wind in the

Northwest, according to a study conducted by a consortium of

investor-owned utilities, publicly owned utilities, environmental

groups, the BPA and others.

Policy initiatives at state and federal levels are proceeding

apace to obtain greater acceptance for wind power among grid

operators. Under guidelines currently being formulated, wind

generators are expected to contribute to grid stability as their

traditional generation-source counterparts have. Cost recovery

is being more adequately addressed after a failure to maintain

adequate construction schedules during the past decade.

Forecasting has become a tool in the integration of wind power

in a way that did not exist a few years ago. Minnesota studies for

Xcel Energy conducted by Enernex and forecasting firm WindLogics

showed wind power’s viability as a capacity resource under certain

conditions. Precise forecasting has the potential to be so reliable

that wind-driven generators may be able to confidently bid into the

day-ahead markets for spot power generation.


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7 in9.75 in

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SIE7006 POWER BASE***The textbox was adjusted to maximize visual effect, it is no long complies with Corporate Guidelines.***

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Increasing concerns about declining assets and aging personnel combined with a focus on improved

reliability and cost containment have given rise to many utilities’

accelerated use of asset management. Progressive utilities have

taken steps to define and assess the potential impact of asset

management for their utilities, but few system-wide deployments

have been initiated. Why is this the case?

The evolution of automated meter reading to advanced meter

infrastructure (AMI) parallels the evolution of asset management in

the electric transmission and distribution industry. The data commu-

nication dilemma is to AMI as the data management and analytics

are to asset management. To cost-justify automated meter reading,

utilities realized the need to leverage the data communication infra-

structure across multiple business applications – giving rise to AMI.

AMI deployment triggered the enormous challenge of managing

massive amounts of data generated by smart devices and the integra-

tion of the data into business applications such as geospatial infor-

mation systems, outage management software, supervisory control

and data acquisition and enterprise resource planning, all of which are

needed for asset management. Utilities have turned to their informa-

tion technology community to resolve the data communications and

management issues. They can no longer afford to manage growing

numbers of isolated applications based on proprietary technologies.

One possible solution to this challenge of moving and managing

data is the implementation of an open infrastructure based on

Internet protocol, agnostic to the transport layer. This would enable

data of all sources to be managed in a consistent manner. Service-

oriented architecture and common information model are also key

standards that will be required for successful implementation and

broad rollouts of AMI and asset management programs. Although

much work remains to validate the performance of those standards,

the success other industries have seen indicates that the probability

of success for transmission and distribution utilities is high.

To cost-effectively manage distributed assets, asset managers

need to rely on data generated from a variety of sources and loca-

tions before converting the data into actionable information through

analytics and visualization. Solving the AMI challenge is a step

forward in the process. Having the right set of data, correlated and

analyzed in the right way, delivered to the right individuals and in the

right format is what asset management is all about. Most utility asset

managers and AMI champions would agree that the cross-functional

nature of their activities requires careful technology road-mapping.

More importantly, the cross-functional aspect also requires a change

in the way a utility does business. That is a true challenge.

Instead of waiting for the ultimate solution, utility asset

managers ought to first establish priorities and address the asset

class or classes that most impact reliability, the bottom line or

both, while their IT counterparts resolve the equally complex issue

of the data management infrastructure.

For example, pole inspection and maintenance, a proportion-

ally large annual expenditure for an investor-owned utility, is an

activity that can be addressed by leveraging readily available infor-

mation to reap great rewards.

Transformer maintenance represents another opportunity. Using

relatively inexpensive smart sensors, an asset manager can monitor

and diagnose incipient problems while using geospatial-based tools to

deploy resources based on the priority and severity of the problem.

Although many sources and types of data combined with

sophisticated analytics are necessary to advance asset manage-

ment, leveraging geospatial information as a first step can lead to

an immediate initial success for asset management.

As utility data communication and management strategy align

with open industry standards, utilities will be able to fully realize

the power of the data across their enterprise, which can lead them

to cost-effectively manage their distributed assets and improve

their overall business performance.

Bob Gilligan is general manager of GE Energy’s transmission and distribution business.

The Challenge of Managing Distributed Assetsby bob GiLLiGan

Bob GilliganPhoto Courtesy of Ge enerGy.

www.energycentral.com EnErgyBiz magazinE 55ThoughT lEadErship — sponsorEd by sprinT nExTEl

Drivers point to outsourcing the utility communications infrastructure.

In a previous Thought Leadership piece in

this series, it was pointed out that because

of the increasing difficulty utilities have

in maintaining communications technol-

ogy currency amid the demands of the

volatile utility business environment,

outsourcing telecommunications may

become a growing trend in the industry.

In this document, we look not only at the

depth and breadth of commercial solutions

and their applicability to utilities but also

at some of the common misperceptions

in the utility industry about the use of

commercial providers for mission-critical

communications.

Some of these common

misperceptions include the

following:

1. Commercialprovidersdon’tprovide

thenecessaryutilitygeographic

coverage.

2. Useofacommercialcarrier

inhibitsutilities’controloftheir

communicationsnetworks.

3. Commercialprovidersareunwilling

towriteservice-levelagreementsto

ensurecommunicationsreliability.

Just as electric, natural gas and water

utilities have been undergoing tremendous

changes in the last 10 to 15 years, telecom-

munications also has evolved rapidly — in

many cases much more rapidly than con-

ventional utilities have. This rapid evolution

of commercial telecommunications carriers

has, in many cases, rendered the three

statements listed previously no longer true.

This is especially true in voice communica-

tions, one of the traditional mainstays of

how utilities do business.

First, to illustrate the volatility and

difficulty that utilities face in maintaining

communications currency in the current

business environment, consider the follow-

ing market forces and issues:

Regulatory

Narrowbandingandrebanding

ofthespectrumbytheFederal

CommunicationsCommission.

NERCCriticalInfrastructureProtection

requirements,whichputincreasing

demandsoncommunicationssecurity.

Rapidlychangingfederallegislation

andregulation — nothingnew,

butsomethingthatdistractsutility

attentionfromcriticaltasks.

Rapidlychangingstateandlocal

legislationandregulation — moreof

thesame.

Rapid Technology Migration

Aged/obsoleteequipment — many

utilitysystemswereinstalledmany

yearsagoandhavebeenmadeobsolete

bynewtelecommunicationstechnology.

Analogtodigital — therapidspread

ofsoftwareintothefieldhasledto

ademandfordigitalcapabilities.

Convertingoldanalogvoicesystems

todigitalisaveryexpensive

proposition.

AdvanceMobilePhoneSystem

sunsetting.

IP-basedsolutions.

Increaseddemandforintegrated

solutions.

Social/Workforce Changes

Agingworkforce.

PRePaReD foR

SPRinT nexTel

By WaRRen B. CauSey

ViCe PReSiDenT

SieRRa eneRgy gRouP

a DiViSion of

eneRgy CenTRal

True or False:are commercial carriers viable alternatives

for private land mobile radio (lMR) ownership for utilities?

56 EnErgyBiz magazinE July/August 2007 ThoughT lEadErship — sponsorEd by sprinT nExTEl

Lackofskilledworkers-U.S.colleges

arenotgraduatingenoughengineers

tofillthedemand,nordohighschools

andtechnicalcollegesprepareenough

youngpeoplefortechnicaltradeslike

thoseatutilities.

Mobileworkerenvironment.

Homeland Security

Businesscontinuityandemergency

preparedness.

Cybersecurity.

ITstandards.

All of these issues are prompting

utilities to adopt different paradigms from

what they have been accustomed to in the

past. These changes already are taking

place at many utilities and eventually

will permeate the entire industry. Among

the trends that already are in evidence

nationwide are the following:

Utilitiesaredemonstratingan

increasingacceptanceofoutsourcing

ofcertainfunctions,albeitvery

selectivelyandataslowerratethanin

someotherindustries.

Graduallythetotalcostofownership

ofcertainutilityassetshasbeen

matchedandbetteredbyoutsourced

solutions.

Maintaininglegacyassetsin

informationtechnologyandclosely

linkedtelecommunicationstechnology

isincreasinglyexpensive.

Itwillcontinuetobeincreasingly

difficulttocostjustifyprivate

telecommunicationsnetworkswhen

commercialsystemsnowarevirtually

ubiquitousinmetropolitanareasand

spreadingrapidlyinmoreruralareas.

Manyutilitiesrecognizethat

telecommunicationsisnotacore

businessfunctionandnolongerhave

theresourcesorthedesiretomaintain

expertiseinanon-corearea.

Utilitiesarerapidlyadopting

technologystandardizationasthe

traditionalsilosofoperations/back

office/frontofficeandotherartificial

barriersbreakdown.

Manytechnologies,suchasglobal

positioningsystemsarereadily

integratedincommercialofferings,

butaremoredifficulttohandlein

privatesystems.

Rapid changes in

telecommunications have

eliminated the perceived barriers

Telecommunications providers like Sprint

Nextel now provide comprehensive offer-

ings to utilities that include, among many

other things, the following:

Rapidbuild-outofnecessarycoverage

inutilityserviceterritories.Carriers

likeSprintNextel,facingintense

competitionthemselves,areeagerto

workwithutilitiestoplaceadditional

towerswherenecessarytoensurefull

coverage.Inmostcases,theutility’s

shareofthesecostsislessthan

upgradingorreplacinganexisting,

obsoletelandmobileradio(LMR)

system.SprintNextelcurrentlyis

workingwithFirstEnergyCorp.in

Akron,Ohio,onsuchabuild-out.

Controlofanetworkspecifictoan

individualutilitynowisbeingprovided

throughseveralprotocolsthatare

availablefromcommercialcarriers.

TheseincludePriorityConnect,which

providespriorityontoSprintNextel’s

nationwidetrunkedradioiDENsystem

andWirelessPriorityServiceforcellular

services,whichisadministeredby

NationalCommunicationsService.

Theseareexcellentexamplesofhowa

commercialcarriercanoffernetwork

controltocustomerswithpriority

designation.Restorationagreements

guaranteetheutility’spriorityin

towerrepairorreplacementintimes

ofdisaster.Theseagreementsalso

delineatetheutility’sresponsibility

forrestoringpowertotowersthat

carrytheirowncommunications.

Increasinglyimportantareagreements

thatdirectthecarriertobuildtelecom

redundancieslikeT1linesforbackhaul

diversityandbackupgenerationfor

increasedreliability.

Finally,communicationscarriers

likeSprintNextelhaveconverted

theirsoftwareoperatingsystemsto

www.energycentral.com EnErgyBiz magazinE 57ThoughT lEadErship — sponsorEd by sprinT nExTEl

service-orientedarchitecture,which

isalsobecominganinternalstandard

atmostutilitiesandtheirother

vendors.Thus,telecommunications

canberapidlyintegratedwith

mobileworkerdevicesandanyother

necessaryinternalutilitysystems.

Despite changes in the way utilities

do business, voice still is critical

One of the important things to remember

is that — despite the evolution of technol-

ogy, the delivery of many work orders

to the field via digital communications

and the updating of mobile devices via

digital service-voice communications is

still vitally important to utilities. There

are some critical circumstances in which

sending a text message digitally just will

not do. This is particularly true in emer-

gency situations, when directions and

responses have to be rapid, in the field and

often away from computers.

It is possible to replicate the traditional

voice communications of utilities, in some

ways, with cell phones, but this also is not as

effective as having a radio, especially a radio

that can be taken anywhere. The problem

with depending on cell phones as a primary

form of communications is that during times

of network congestion and emergencies, the

cellular calls can be blocked, connections

dropped or not connected at all as was seen

during 9/11 and the recent London subway

bombings. Sprint Nextel’s iDEN network

provides digital communications, cell phone

voice coverage, and mobile radio — all on the

same handheld device.

The Sprint Nextel Direct Connect LMR

system provides voice communications

with the push of a button anywhere within

their iDEN system across the United States.

As shown in the chart, it is unique in that

it represents a nationwide Direct Connect

environment that does not rely on the

public switched telephone network (PSTN).

The system supports pairing or grouping

of different individual devices so that work

groups or emergency response groups can

be on the same “talk group” at the same

time. It also provides various methods for

prioritizing calls. Also, like the radio systems

that utilities are accustomed to, Direct

Connect can also be offered with a “man

down” emergency feature on selected hand-

sets, something that cannot be provided by

cellular service alone.

Putting voice together with cellular

service and wireless transport for transmis-

sion and distribution devices — supervisory

control and data acquisition (SCADA) as well

as digital communications with field devices

— has, for the first time, allowed companies

like Sprint Nextel to offer the complete wire-

less telecommunications services that are

required by utilities.

Sprint Nextel, together with various

partners, provides all three of the critical

types of communications required by utilities

today: mission-critical, mobile wireless;

digital enablement; and remote automation.

Remote automation is becoming increasingly

important as utilities move toward intelligent

grids and intelligent enterprises in which

distribution networks become increasingly

self-reporting and self-healing. High-speed,

reliable communications networks will be

required in order to enable such distribution

networks. These three critical communica-

tions types are now available commercially.

The idea is catching on

As utilities face the reality of all the demands

for communications in the new environment

in which they find themselves, an increasing

number of them are outsourcing a variety

of services. However, this is an evolutionary

process. Few utilities — with their traditional

cultural backgrounds — are eager to turn

over vital processes all at once. Thus, as

it has developed, utilities have opted for

various stages of outsourcing telecom-

munications. Carriers such as Sprint Nextel

are enabling this process by offering options

such as the following:

1. Providingsole,primary

communications.

2. Providingprimaryserviceandusing

anoldersystemasaredundant

backupsystem.

3. Providingbackupredundancyto

privatesystems(cellular,messaging,

dataandGPSlocationservices).

With most commercial carriers, all of

these options now are on the table when

58 EnErgyBiz magazinE July/August 2007 ThoughT lEadErship — sponsorEd by sprinT nExTEl

utility personnel sit down to discuss

upgrading or supplementing existing LMR

systems. Commercial carriers also provide

products that operate exactly like the

trunked radio systems they are familiar with.

Commercial carriers now provide end-to-

end services, from handheld devices in the

field through the network to software and

back-end systems that can be integrated

with existing utility IT architectures for full

integration throughout the enterprise.

Another advantage of commercial

carriers for utilities is the cost of the hand-

held hardware itself. Mobile radios for LMR

systems can range from $1,000 to $3,000

or more each. Handheld iDEN devices from

Sprint Nextel can be acquired in quantity for

$50 to a few hundred dollars each.

Utilities that already have outsourced

communications include ConEdison of

New York, which now uses a mix of private

and commercial communications systems

throughout its highly populated service

territory. ConEdison has a multiyear profes-

sional services contract with Sprint Nextel

to manage their existing LMR system, along

with heavily relying on the iDEN system for

day-to-day dispatching. Other utilities that

rely on Sprint Nextel’s iDEN system include

SM&P Utilities, Tennessee Valley Authority,

Pacific Gas and Electric, Peoples Gas, Los

Angeles Department of Water and Power and

Potomac Electric, to name a few.

Cullman Electric Cooperative of Cullman,

Alabama, has partnered with Sprint Nextel

to provide GPS-based vehicle tracking and

communications for outage management.

The solution provided by Sprint Nextel is the

Air-Trak system, which also has a satellite

data backhaul, so field crews are always in

communication.

FirstEnergy, which was mentioned previ-

ously and which was covered in the first

article of this series, is partnering with Sprint

Nextel to build out complete voice and data

services to 95% of its service territory, which

includes seven subsidiary operating utilities.

emergency response teams provide

the backup that utilities demand

Probably the most serious concern that

utilities have had in the past about relying

on commercial carriers for their primary

communications system has been the issue

of restoration of service during emergencies.

Voice communications are critical during res-

torations from relatively minor thunderstorms

to major catastrophes such as hurricanes.

A utility that has partnered with Sprint

Nextel will find that it has instantaneous

connection with all of the major emergency

operations centers in the United States. In

addition to this widespread connectivity,

a utility that outsources communications

to Sprint Nextel has three backups for

emergencies:

1. SprintNextelnegotiatesservice-

restorationagreementsthatprovide

thenecessaryguaranteesduring

emergencies.

2. SprintNextelhasemergencyresponse

crewswithspecializedrestoration

equipmentpre-positionedthroughout

theUnitedStates.

3. SprintNextelalsohasalargenumber

ofCellsonWheels(COWs)positioned

throughouttheUnitedStates.These

self-containedvehiclescanbesetup

almostimmediatelyinanyremote

area,andtheyincludecelltowersand

portablepowersystemstoprovide

immediatecoverageinanyarea.

While utility executives have been

traditionally slow to outsource many of what

they consider to be core functions, the one

area in which they are increasingly likely

to be forced to consider partnership with

services is in telecommunications. Regula-

tory demands for better security, rapidly

changing telecommunications regulation and

technology and the evolving communica-

tions needs of intelligent utility enterprises

and intelligent grids make it very difficult

for utilities to continue to rely upon their

traditional, outdated LMR voice systems.

In addition, pressures from all directions-

including new environmental regulation,

aging workforces and changing business

environments-make it difficult for utilities

to update or expand their current telecom-

munications systems. Commercial carriers

like Sprint Nextel, however, have communica-

tions as their primary core competency and

function. They can bring the latest technology

to the table. And, in a fiercely competitive

environment themselves, commercial carriers

now are prepared to negotiate partnerships

with utilities to expand coverage, guar-

antee reliability and security and meet the

other important needs of utilities. Thus, the

common misperceptions about commercial

carriers no longer apply.

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For more information, please visit our Web sites, www.cooperpower.com, www.cannontech.com or www.cybectec.com or call 1-877-CPS-INFO.

Enspiria Solutions, Inc.6560 S. Greenwood Plaza Blvd., Suite 500Greenwood Village, CO 80111(303) 741-8400Fax (303) 799-6766www.enspiria.comContactCindy Menon, PMP Marketing Manager

(303) 520-2513 [email protected]

Mehrdod Mohseni, Vice President, Business Development (303) 521-5395 [email protected]

Enspiria Solutions, Inc.TM provides T&D con-sulting, solution development, and systems integra-tion services, specializing in Asset Management, Metering and Demand Response, Distribution/Substation Automation, Field Force Automation, GIS, Outage, and Mobile and Work Management. Enspiria’s Enterprise Asset Management (EAM) approach optimizes investment and work planning through the asset lifecycle – to reduce capital project requirements and O&M budgets while maintaining or improving system reliability, safety and risks, and asset utilization. Enspiria is backed by parent company Osmose Holdings, Inc., with $596M annual revenue. Enspiria’s subsidiar-ies include Convergent Group Corporation and Convergent Group LTD (Canada).

ESRI380 New York St.Redlands, CA 92373(909) 793-2853Fax (909) 307-3039www.esri.comContactRoxanne Cox-Drake, Electric & Gas

Utility Manager (909) 793-2853 x1-2689

ASSET MANAGEMENT

SOURCEBOOKWith annual sales of more than $660 million,

ESRI remains the world leader in the geographic information system (GIS) software industry. Our business involves the development and support of GIS software for all types of organizations — from the one-person office to multinational corporations to innovative Internet GIS solutions. As the leader in GIS technology, ESRI offers innovative solutions that will help you create, visualize, analyze, and present information better and more clearly.

IFS10 N. Martingale Road, Suite 600Schaumburg, IL 60173(888) [email protected]

Throughout the world, IFS provides industry-focused software solutions that help leading companies — and some of the largest utilities in the world — to maximize uptime, meet regulatory requirements, and take advantage of new busi-ness opportunities. Because it is built on open standards, IFS Applications makes it easier to stay up-to-date with technology and to integrate with legacy systems. IFS Enterprise Asset Management delivers best-of-class EAM functionality that lets you maximize uptime and efficiency. The application provides valuable support for the company’s stra-tegic and operative processes, as well as being an efficient tool for increased availability, productivity, and lower Life Cycle Cost.

Itron2111 N. Molter RoadLiberty Lake, WA 99019(800) 635-5461Fax (509) 891-3932www.itron.comContactTim Wolf, Marketing Communications Manager

(800) 635-5461

Itron is a leading technology provider and criti-cal source of knowledge to the global energy and water industries. Nearly 3,000 utilities worldwide rely on Itron’s award-winning technology to pro-vide the knowledge they require to optimize the delivery and use of energy and water. Itron creates value for its clients by providing industry-leading solutions for electricity metering; meter data col-lection; energy information management; demand response; load forecasting, analysis and consult-ing services; distribution system design and opti-mization; web-based workforce automation; and enterprise and residential energy management. To know more, start here: www.itron.com.

ABB Inc.Power Technologies Division2945 Harding St., Suite 207Carlsbad, CA 92008(760) 720-6198Fax (760) 720-2861www.abb.usContactJohn Barnick

(760) 720-6198

Now more than ever, Utility companies are looking for ways to apply intelligent, comprehensive solutions to manage their networks. ABB offers an array of tools to support these activities. With sophisticated planning and analysis tools such as network asset documentation, load forecast modelling, reliability assessment and optimization studies, ABB’s solutions delivers the capabilities needed to optimize network asset performance. ABB also offers specialized training and project support services to help Utility companies to realize their goals.

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505 Highway 169 N., Suite 1200Minneapolis, MN 55441(800) 827-7966Fax: (763) 543-7777www.cooperpower.com

The Cooper Power Systems Energy Automa-tion Solutions group offers comprehensive automa-tion solutions that extend from the meter to the control room, enabling the smart grid today. The portfolio includes intelligent products tied together with Cooper’s recent acquisitions of Cannon Technologies’ Yukon® Advanced Energy Services Platform and Cybectec’s Enterprise Gateway.

The solutions offered include automated meter reading/advanced metering infrastructure, demand response, centralized capacitor bank monitoring, substation integration and monitoring, feeder auto-mation, asset monitoring for high voltage breakers and power transformers, recloser and regulator controls, protective relays and NERC-compliant enterprise-wide substation data solutions.


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OSIsoft777 Davis St., Suite 250San Leandro, CA 94577(510) 297-5800ContactRon Kolz, VP Sales, North America

(440) 720-3670

OSIsoft (www.osisoft.com) delivers the PI System as the core of its powerful operational data management framework. The world’s leading process manufacturing, life sciences, and utility companies rely on OSIsoft’s Platform wherever real-time data fuels performance. With more than 11,000 installations worldwide, OSIsoft’s Real-time Data Platform crosses IT and process boundaries to incorporate and display operational information. Founded in 1980, OSIsoft, Inc. is headquartered in San Leandro, Calif., with opera-tions worldwide and is privately held.

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General Manager Utilities Lisa Dalesandro, Vice President Utilities;

US Eastern RegionTrent Brown, Vice President Utilities;

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Gain greater agility and control across your “asset-intensive” organization. Managing asset – defined broadly to include human, financial and physical assets – is vital to utilities in the new and rapidly changing environment. To meet regulatory compliance and customer satisfaction goals, you need a holistic view of your enterprise, provided in real time. SAP software delivers a compre-hensive enterprise asset and work management solution, so managing assets is easier, more fully automated, and timely.

Siemens Power Generation4400 Alafaya TrailOrlando, FL 32826(407) 736- 2000Fax (407) 736-5008www.siemens.com/powergeneration

Siemens Power Generation develops and delivers technology-based solutions for power plants, including gas, steam and wind turbine generator technology; process control and power management systems; operations and mainte-nance support; power plant modernization and upgrades; and environmental care solutions.

Siemens Power Transmission & Distribution7000 Siemens RoadWendell, NC 27591(919) 365-2200www.usa.siemens.com/energy

Siemens Power Transmission & Distribu-tion, Inc., creates innovative product, system and service solutions for its customers — electric utilities, transmission organizations, Independent System Operators, and large energy consumers. It is a leading supplier of high and medium voltage power delivery equipment, energy management systems, network planning and power system engineering software for regulated and deregu-lated generation, transmission, and distribution markets. The company’s products and systems are used to increase power system capacity and improve the reliability, stability and flexibility of power delivery and network control systems.

UMS Group Inc.5 Sylvan Way, Suite 120Parsippany, NJ 07054(973) 335-3555Fax (973) 335-7738www.umsgroup.comContactMike Scholtens, Vice President-Global

Asset Management Practice (253) 241-1705

UMS Group is an international Management Consulting firm specializing in the practice of utility asset management, performance assessment and performance improvement. We combine experienced consultants and seasoned industry professionals with world class tools and intellectual capital to assist clients in diagnosing problems, designing pragmatic solutions, and implementing change. UMS consultants are Asset Management strategy, process and solutions thought leaders who serve our clients with a knowledge of global best practices, a proprietary database of perfor-mance metrics and pragmatic process solutions and tools. UMS solutions have been utilized by over 300 electric, gas, and water clients on four continents to build world-class operations.

KEMA Inc.67 S. Bedford St., Suite 201EBurlington, MA 01803(781) 273-5700Fax (781) 229-4867www.kema.comContactSusan Erwin, Director, Corporate Marketing

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KEMA provides energy consulting, tech-nology implementation, testing services and market knowledge expertise to more than 500 energy and utility clients in over 70 countries. KEMA’s multi-dimensional approach bridges the gap between the strategists and the implement-ers, and the engineers and the accountants to effect lasting change. Founded in 1927, KEMA serves the complete spectrum of participants in the energy marketplace, offering a full comple-ment of services supporting generation through the consumer side of the meter.

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Linda Jackman, Vice President – Product Management, Utilities Global Business Unit (415) 963-5769

Oracle l SPL delivers the proven software applications that help utilities around the world achieve competitive advantage and excellence in business performance, while ensuring a lower total cost of technology ownership. Available stand-alone or as a pre-integrated suite, Oracle l SPL solutions in customer care and billing, enterprise work and asset management, mobile workforce management, network manage-ment, meter data management and business intelligence are specifically designed for energy, water, and service companies. Our solutions focus on clients’ return on investment and foster long-term relationships based on confidence and trust. For more information visit oracle.com or call +1-800-275-4775.


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