FERC vs NERC: A grid control showdown over cyber security

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cyber security 

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CONTENTS 

WWW.INTELLIGENTUTILITY.COM /// JULY/AUGUST 2011 

2 

FEATURES // JULY/AUGUST 2011 

Regulatory Intel 

14 

17 

FERC vs NERC 

A cyber security showdown in the bulk 

power system corral? 

Establishing coherent policy 

Ex-FERC commissioner Suedeen Kelly 

provides transmission insight 

Distributed generation redux 

20 

Solar solutions 

Distributed load or microgridding—or both? 

Utility mobility 

24 

Integrating mobile solutions 

Three utility leaders describe their 

challenges, successes and lessons learned 

14 

10 

20 

34 

38 

40 

SPECIAL REPORT 

COMMUNICATIONS NETWORKS 

32 

No one size fits all 

Network of networks requires 

combination of solutions 

DEPARTMENTS 

4 

Drawing the line 

6 Transmissions 

6 Letters from readers 

10 

The big picture 

10 DMEA finds common ground 

in diverse constituency 

34 Grid(un)lock 

34 Nashville Electric Service 

pursues voltage conservation 

38 

40 4D 

End of the Line 

38 A new attitude toward 

energy consumption? 

40 Hydro One: 

Location is imperative 

44 Connections 

44 Cyber security requires 

organic effort 

48 

Out the door 

48 The advanced smart grid: 

book excerpt 

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DRAWING THE LINE 


4 

Overtaking the noise 

I WAS IN SANTA CLARA, CALIF., IN LATE MAY TO PARTICIPATE IN A CONSUMER 

symposium and to moderate a panel for ConnectivityWeek. I arrived there armed with 

Benadryl (for heavy pollen) and empty notebooks (for heavy note-taking). I arrived home a few 

days later with full notebooks and a head full of new ideas. 

Since then, a suggestion made by one plenary speaker, Geoffrey Moore, has been challenging me. 

Moore, a Silicon Valley-based high-technology consultant and author of 

Crossing the Chasm and other books, opined that the smart grid has not 

yet achieved escape velocity in order to “cross the chasm” to a volume 

operations model. 

“The volume operations model doesn’t kick in until there’s enough volume 

for the operations model work and payoff,” Moore told us. “You’ve got 

to play this game as a complex systems game ... for the foreseeable future.” 

But it was something else Moore said that I’ve been thinking about since 

I arrived back in the office. 

“Identify the narrative that will take you to the next place. When the 

narrative is clear enough, the signal overcomes the noise,” he said. “As 

long as there is more noise than signal, the world will say, ‘Let’s wait 

until next year.’” 

Since its inception more than two-and-a-half years ago, Intelligent Utility 

magazine has been working to identify the evolving narrative of the electric 

utility industry and the smart grid. As projects and technology have 

continued to evolve, so have the stories within our pages. 

In this issue, we cover a gamut of issues and utility stories, all contributing 

to the narrative that will take us, as an industry, to the next place. 

My challenge to you, as a reader and participant in this evolving industry, is this: 

Where is the electric utility industry now with respect to noise and signal? Has the signal overtaken 

the noise? And, if not, what’s it going to take to get us there? 

As always, I enjoy hearing from you, and appreciate your feedback. 

Kate Rowland 

Editor-in-Chief, Intelligent Utility magazine 

krowland@energycentral.com 

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TRANSMISSIONS 


6 

Vol 3, issue 3 » mAy/June 2011 

Letters from readers 

smARt sm smARt t gRiD gR gRiD iD 

2020 

© 

Industry experts weigh 

in on critical trends 

tRAnsmission 

inteRconnection 

two new developments 

putting the brakes on buildout 

eneRgy eFFiciency impAct 

How DR + ee is more than 

the sum of their parts 

where smart grid meets business—and reality. 

cis/mDm 

utility barriers still exist 

» www.intelligentutility.com 

Grid modernization 

monetization 

March/April 2011 

Thank you for the interesting article 

on ROCs. I had not previously heard 

of this sort of financial instrument, 

although it sounds a lot like a municipal 

revenue bond. Those instruments 

are tax-free and are low risk because 

of the dedication of project revenues 

to repay the debt. I like the long-term, 

stable source of capital that an ROC 

represents so that the payment stream 

can be more stable. 

I am curious about a few things. 

Firstly, long-term finance and amortization 

is common in the utility sector, 

but with smart grid assets the steep 

technology curve dictates much shorter 

amortization periods like 10 years instead 

of the typical 30. If the underlying 

assets become no longer useful before 

the debt is repaid, how is the remaining 

balance paid? In utility ratemaking, 

utilities can only have assets that are 

used and useful in rate base. 

I understand from a credit standpoint 

why the instrument’s marketability 

and lower interest rate is tied to 

the dedicated charge on consumers’ 

bills along with a true-up mechanism 

and assurance from regulators that 

the deal will be honored over the term 

of the loan. However, this very issue 

of providing assured cost recovery, or 

prudence, is a major issue for regulators 

as evidenced best in the initial 

order last June from the Maryland 

Commission re: denying BG&E cost 

recovery for its AMI project. 

I am intrigued by the ROC, but 

wonder what thought has been given 

to satisfying or assuring regulators 

relative to performance, ratepayer 

benefit that would convince a PUC to 

provide the sort of iron-clad support 

contemplated in an ROC? Have any 

ROCs been placed at this point that 

would be instructive along these lines? 

David O’Brien 

Director Regulatory Strategy 

Bridge Energy Group 

Changing the 

dispatch equation 

March/April 2011 

We continue to look at our mounting 

problems through the lens that we 

have used since the grid was created. 

“We need to bring more data into 

the equation and find a way for 

dispatchers to manage it,” the gist of 

this article, is based on a top-down, 

center-based control paradigm. We 

need much more data, that is certainly 

true, but more data will overwhelm 

our current system. Consider how 

the Internet manages complexity and 

massive amounts of data. The communication 

protocols of the Internet 

(TCP/IP, etc.) enable massive amounts 

of data to self-route. They provide 

an appropriate network architecture 

to manage complexity and, in so 

doing, unleash tremendous potential 

for innovation and, importantly for 

www.intelligentutility.com 

EDITOR-IN-CHIEF Kate Rowland 

krowland@energycentral.com 720.331.3555 

SENIOR CONTRIBUTORS 

Phil Carson 

Editor-in-chief, Intelligent Utility Daily 

pcarson@energycentral.com 303.228.4757 

Christopher Perdue 

Vice President, Sierra Energy Group 

cperdue@energycentral.com 310.471.7396 

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TRANSMISSIONS 


8 

www.intelligentutility.com /// may/June 2011 

the grid, this approach would enable 

exception-based management 

by dispatchers. 

With a shift to a bottom-up, edgebased 

control paradigm, potential 

solutions become more feasible, 

because now they better match the 

problem. The key to managing an 

incredibly data-rich grid will be 

opening up to new players and 

Smart Grid 

2020 

Where are we going? 

We decided to plumb the depths of our own crystal ball, 

and asked analysts, researchers and national laboratory leaders 

where they think the industry is headed in the coming 

Gazing into 

decade, and what we can expect come 2020. 

data analytics on the rise 

the future of 

In early January, Pike Research released data indicating that 

the software and services that will enable smart grid data 

the new utility 

analytics will represent one of the largest growth opportunities 

in the utility sector over the next few years, increasing 

+ Some elements are 

from a relatively small market of $356 million last year to 

more hazy than others 

nearly $4.2 billion in annual revenue by 2015. 

By Kate Rowland 

And there are clear indicators this trend will continue into 

2020. “Data analysis is the area which is just emerging as a 

It’S generally agreed that the comIng need: ‘Okay, I now have the systems in place and have lots 

decade will bring more change to our industry of data, but what do I do with it?’” said John Wambaugh, a 

than we’ve seen in the previous century. 

vice president of Utility Integration Solutions (UISOL). “My 

Industry researchers have clearly indicated they see a favorite quote is, ‘I have 100 times more data, and I still can’t 

massive increase in smart grid spending between now and tell where the problem is.’” 

2015. Late last year, SBI Energy was definitive in its expec- In my own conversations with utilities and vendors 

tion that “The next five years will be a pivotal period for the alike, especially over the past year, the subject of struc- 

global smart grid market, with grid component companies tured and unstructured data analytics has crept into 

expected to leverage their sales prowess to capture long-term the discussions more and more often. As Craig Johnston, 

contracts throughout the electric grid supply chain.” OGE Energy Corp.’s vice president, corporate strategy 

But what about 2020? 

and marketing, told us recently about his utility’s data 

16 

new possibilities, letting go of some 

elements of control and changing the 

paradigm. Managing data as it comes 

into the system, out at the edge, for 

example, reduces the data that must 

be carried over the communication 

system. Intelligent edge devices as 

well are needed to substitute for 

better equipped dispatchers. 

John Cooper 

Ecomergence 

I agree with Dr. Harris that more gridlevel 

data needs to be made available. 

I also agree with him that knowing 

the state of the grid is more valuable 

than estimates of the state of the grid 

(hence the term “state estimator”). 

However, I’m not as sanguine about 

the prospects for “perfection” and 

“optimality” in a smarter grid with 

more actors. Dispatchers, and dispatch 

algorithms, face limitations on computing 

power and the availability of 

information. Consumers are not going 

to sit quietly while a faceless individual 

in Valley Forge decides when their air 

conditioner can run, and when dinner 

IlluStratIon by dana lechtenberg 

needs to be put off for the sake of 

economic efficiency. 

If we’re really serious about engaging 

consumers in this grid modernization 

effort we call the “smart grid,” 

then consumers have to be in charge, 

not the dispatchers. Rather than exercising 

control over the grid, dispatchers 

monitor the grid, signal when the 

grid is out of balance, and only step 

in when automation 

on the edge of the grid 

can’t or won’t keep the 

grid from collapsing. 

I think some policymakers 

are very serious 

about engaging 

consumers, but they 

have no idea what’s 

required and what the 

ramifications are. 

www.intelligentutility.com 17 

Jack Ellis 

Tahoe City, CA 

Smart meter 

manufacturers join forces 

Intelligent Utility Daily, June 21 

I find the need for the smart meter 

manufacturers association both 

interesting and sad. 

I am speaking from personal firsthand 

experience and interaction with 

several of the smart meter manufacturers 

who have created this association. 

I have had extensive personal 

experience with different utilities from 

across the nation involving smart 

meter uses and deployments. I fully 

understand the needs of the manufacturers 

in undertaking such efforts to 

protect their bottom line. After all, this 

is their business and, as stated in the 

article, some have been in the business 

for 100 years or more. The manufacturers 

have maintained a product 

reliability record that can be easily 

verified and defended with astonishing 

results. This too is pointed out by the 

reports given in the article. 

The sadness I feel is over the lack of 

“clear” utility leadership in the efforts. 

I believe the bottom-line reason for 

the consumer pushback is not because 

of smart meters per se, but more 

about consumer frustration and lack 

of voice. The smart meters are just the 

newest lightning rod attracting the 

pent-up anger/energy of the consumers. 

Utilities have done a very poor 

job of presenting consumer benefit 

cases to the public, and the consumers 

know that they will be charged for the 

deployment of these new technologies 

with questionable benefits for themselves. 

The utilities will be the ones 

who gain the greater benefits if the 

present business cases are used. 

The failure of utilities to understand 

Marketing 101 and build products that 

people want and are willing to pay for, 

I believe, is the root of the problem. It 

is not the smart meter that has failed, 

but the utility business cases presented 

to consumer with thinly veiled 

consumer benefit packages. These 

packages are being quickly disrobed, 

by the consumers themselves I might 

add, as another effort to raise rates and 

increase utility revenue. 

I applaud the smart meter manufacturers 

for trying to step in as responsible 

players. Their main problem is 

that the real players are still sitting 

in the stands watching the game. 

Unfortunately for them (the utilities), 

they do not fully realize the changing 

game rules, nor do they see the new 

players standing in the wings ready to 

run onto the field. Most of the existing 

utility players will not be around in the 

near future, and the changes will come 

fast and furious. 

Richard G. Pate 

Pate & Associates 

To contribute to the 

Transmissions department, 

please e-mail your submission to 

intelligentutility.editor@energycentral. 

com. Provide your name, address and 

daytime phone number. Letters may be 

edited for style and space.

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THE BIG PICTURE 


10 

DMEA finds 

common ground in 

diverse constituency 

+ + The focus: What’s in it for the members? 

By Phil Carson 

WEST OF COLORADO’S CONTINENTAL DIVIDE, WHERE THE 

Gunnison River drains a vast and varied topography, a small rural 

electric cooperative has maintained a face to the future since President Taft 

dedicated the local South Canal for irrigation in 1909. 

In those days, just bringing water and, later, electrification to the region were 

the simplest priorities. Both resources served traditional farming and ranching 

needs and the small towns that sprouted here. 

Diverse constituency a challenge 

Today the Delta-Montrose Electric Association, or DMEA, distributes electricity 

to not only farms and ranches but also two large coal mines, an array of commercial 

and industrial customers and urban and rural 

homes. Commercial customers range from dairy farms 

to a candy factory, from snowboard and fly rod manufacturers 

to aerospace-related industry. 

DMEA serves about 35,000 metered accounts across Montrose County, most 

of Delta County (except the town of Delta) and part of Gunnison County. To 

serve this sprawling territory, DMEA has embraced strategies and technologies 

that drive out operational costs and prepare it for future contingencies. 

Its first challenge is to unite its diverse constituency around common goals. 

The co-op membership’s diversity was on display in recent town hall meetings 

led by the National Rural Electric Cooperative Association (NRECA), where 

co-op members ranged from conservative ranchers to latter-day hippies. 

One observer noted the meetings’ “heated discussions” and “highly charged” 

atmosphere as locals aired their disparate perspectives and concerns about 

DMEA’s initiatives. Yet common cause emerged around support for DMEA 

actions to help the local economy, promote local self-sufficiency and adopt 

measures to control costs over the long run. 

Utility side first 

The advent of deregulation more than a decade ago jolted this co-op. Large 

power providers might cherry pick the co-op’s largest industrial customers, 

skewing the rate base and sending bills sky high for residents and small businesses. 

Thus began two decades of innovation. 

In the 1990s the co-op began to market and install geothermal heat pumps 

and joined other co-ops in providing members with Internet connectivity via a 

fiber-optic network. In the 2000s it experimented with fuel cells and the potential 

of vehicle-to-grid power, drawing the interest of BusinessWeek. Today the co-op 

is adding hydro power on the South 

Canal and offering shares in community 

solar arrays that will provide the 

limit of local generation (5 percent) 

allowed under DMEA’s contract for 

bulk power from Tri-State Generation 

and Transmission Association, Inc. 

Power from methane gas and biomass 

is being explored as well. 

But these high-profile projects 

shouldn’t obscure the co-op’s dedication 

to its membership’s fundamental 

need for low-cost power and a degree 

of control over its destiny. 

“Our philosophy is to drive out 

costs through technology, best practices 

and energy efficiency for us and 

our customers,” said Steve Metheny, 

assistant general manager.

“ 

The utility side of this strategy 

has in the past included implementing 

a SCADA system and an AMR 

system with interval meters. Today 

it means analyzing life-cycle costs 

when considering technology choices 

in general, and adopting a meter 

data management system in particular. 

By participating in NRECA’s 

multi-utility, stimulus-funded 

project, DMEA will also assess its 

members’ interest in prepaid accounts, 

in-home energy displays and direct 

load control measures. 

Members and smart grid 2.0 

On the membership side, which 

Metheny dubs “smart grid 2.0,” the 

co-op must answer the basic member 

question: “What’s in it for me?” 

“If we provide members with energy usage information, that puts control in 

the members’ hands,” Metheny said. “We’re testing now to determine how many 

members would use such a system.” 

Engaging DMEA’s membership and providing them with energy management 

tools underscores the co-op’s essential mission, according to Dan McClendon, 

the co-op’s general manager. 

“We try to give people the education and the technical tools to manage their 

electricity use to help themselves and the group,” McClendon said. “But education 

doesn’t happen overnight.” 

DMEA’s consistent outreach should pay dividends as the conversation with 

its membership becomes more complex. While 

the co-op has conducted a direct load control 

If we provide 

pilot program for hot water heaters since 2005, 

topics such as prepay, time-of-use rates, in-home 

members with 

displays and, inevitably, future rate increases are 

coming to the table. 

energy usage 

Smart grid 3.0 will be when the two sides interact 

productively, perhaps employing distributed 

information, that 

generation, energy storage, dynamic pricing, 

electric vehicles—you name it, co-op managers 

puts control in the 

say. Moving forward will require consensus. 

Mark Kurtz is DMEA’s newly hired smart grid 

members’ hands. ” 

coordinator. While he recognizes the co-op’s 

diverse membership, he says they’re not that far 

apart on concerns about environmental impacts and interest in energy efficiency. 

He knows that messaging around future initiatives will be crucial. 

“‘Smart grid’ has a bit of tar on it now,” Kurtz said. “We’ll build message 

around ‘empowering the consumer.’ So our messaging will be: ‘Your bill may 

increase by x amount, but if you use these tools, you can mitigate that increase.’” 

Sticking with the basics 

Preparing for a newfangled future is all well and good, but down at the Elk Creek 

Mine near Somerset, the main concerns remain cost and reliability—and predictability. 

Mine operator Oxbow Mining LLC uses nearly 40 million kWh per 

year to produce its high-BTU, low-sulfur coal, which serves power plants east of 

the Mississippi. Along with Arch Coal, Inc., the two mines are the co-op’s largest 

customers and the county’s highest taxpayers. 

Electricity costs directly influence Oxbow’s cost per ton and thus revenue and 

profit. Reliability is critical to operations; the mine has no meaningful backup 

power. Predictability, however, involves visibility into the future on costs and 

business sustainability. So the mines have vital reasons for keeping track of 

DMEA’s direction. 

“DMEA has been good to notify us of proposed changes, including rate 

increases, in the past,” said Rob Bowman, a financial analyst at the mine and 

a newly minted member of the co-op’s advisory board. 

Sticking with bottom-line basics, while reaching for the best practices of the 

future, has garnered DMEA its share of attention from the outside world. 

“A large part of our success is how we share and promote our experiences,” 

said McClendon, the general manager. “We let the world know what we’re trying 

to do. We build relationships at the state and federal level. They hear our story. 

Among our co-op peers, more and more of them are working on the kinds of 

things we’re working on. So I’m glad our story is getting out.” 

Phil Carson is editor-in-chief of Intelligent Utility Daily. 

WWW.INTELLIGENTUTILITY.COM 11

THE BIG PICTURE 


12 

PROJECTS AT A GLANCE 


The project list at DMEA is lengthy. Here are a few 

more salient details about each, with links to even 

more information. 

HOME ENERGY EFFICIENCY 

DMEA has provided an online “Home Energy Savers” 

booklet, offering tips to customers on saving 

energy and money at home. It can be viewed here: 

http://www.dmea.com/index.php?option=com_ 

wrapper&view=wrapper&Itemid=105 

The co-op also offers its customers 

home appliance rebates, explained here: 


content&view=article&id=74&Itemid=107 

KILL A WATT METERS 

DMEA last fall donated 15 Kill A Watt electricity 

usage monitors to the libraries within the company’s 

service territory. These devices can now be checked 

out, like any other library materials, and used by 

members at home to plug in their 110-volt home 

appliances and other electronic devices to determine 

their electrical draw and the resulting cost. 

SOUTH CANAL HYDROPOWER PROJECT 

The South Canal Project, a combined effort between 

DMEA and the Umcompahgre Water Valley Users 

Association, is part of the two groups’ commitment 

to developing western Colorado’s hydropower 

potential. The two filed for a federal release of 

power privileges to use the run-of-river flow of 

water coming through the Gunnison Tunnel for 

approximately six MW of generating capacity. The 

hydroelectric plant, announced in September 2009, 

is considered one of the largest renewable energy 

facilities in western Colorado. 

The project has an historical connection, as 

well as the added bonus inherent in being a runof-river 

project: no dam construction in necessary. 

As far as the history is concerned, the six-mile 

Gunnison Tunnel was first opened in 1909 by 

then-U.S. President William Howard Taft. More 

information on the project is available here: 



COMMUNITY SOLAR ARRAY 

As of April 2011, DMEA’s community solar array 

was fully leased, and the co-op is exploring a 

potential second phase to 

the project. In the first 

phase, both residential 

and business co-op 

members were offered 

the opportunity to lease 

a portion of DMEA’s two 

10-kW photovoltaic solar 

electric arrays, with leases 

starting at a one-time 

$10 payment, ranging up to 

$10,000 worth of capacity. 

Members leasing a portion 

of the solar array receive 

a credit on their electricity 

bills each month for the electricity their portion 

of the array produces. 

Each $10 block leased provides members with 

2.67 watts of solar capacity in the array (an estimated 

annual bill credit, per $10 block, of about 

50 cents). More information is available here: 



NET METERING 

DMEA’s net metering policy encourages its members 

to install solar, wind, hydro and other renewable 

generation devices up to 25 kilowatts (aggregate 

nameplate capacity at one metered location) to 

either fulfill or partially fulfill their own electricity 

requirements. Interconnection standards are also 

set, and applications must be made to the co-op. 

Information is here: http://www.dmea.com/images/ 

stories/PDF/netmetering_policy.pdf 

—with files from the Delta-Montrose Electric Association

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14 

Regulatory 

>> 

FERC 

versus NERC 

+ + A cyber security showdown? 


THE DEFINITION OF THE BULK POWER SYSTEM 

is in play—within certain circumstances—in new 

electric utility cyber security legislation currently moving 

through Congress, both via the U.S. House of Representatives 

and the U.S. Senate. So, too, is the potential reach and control 

of the Federal Energy Regulatory Commission (FERC) 

being stretched by the proposed new legislation. 

It’s an issue with the potential to draw a line in the sand 

with regard to federal versus state regulatory control over 

certain aspects of the electric grid, and it’s already being met 

with sparks, albeit polite ones ... so far. 

Defining the bulk power system 

Let’s begin this chapter in the latest regulatory saga by assessing 

the current definition of the bulk power system. 

Under the Federal Power Act (FPA), Part 39 (Rules 

Concerning Certification of The Electric Reliability 

Organization; And Procedures For the Establishment, 

Approval and Enforcement of Electric Reliability Standards), 

the bulk power system is defined as “facilities and control 

systems necessary for operating an interconnected electric 

energy transmission network (or any portion thereof), and 

electric energy from generating facilities needed to maintain 

transmission system reliability.” 

It’s important to note the last part of this definition: “The 

term does not include facilities used in the local distribution 

of energy.” Nor does it apply to Alaska and Hawaii, or to 

some transmission facilities. 

On August 8, 2005, the Electricity Modernization Act of 

2005 (Title XXI, Subtitle A, of the Energy Policy Act of 2005, 

or EPAct 2005) was enacted into 

law. EPAct 2005 added a new 

section 215 to the FPA requir- “ Existing pracing 

a FERC-certified Electric 

Reliability Organization (ERO) 

tices should be 

to develop reliability standards, 

which are subject to FERC 

enhanced, not 

review and approval. Once preempted, by 

approved, these reliability standards 

become mandatory and grid cyber secu- 

may be enforced by the ERO, 

subject to FERC oversight. rity legislation. 

In July 2006, FERC certified ” 

the North American Electric 

Reliability Corporation (NERC) as the ERO. ” 

Rocking the boat 

But there are new waves rocking the boat. Approximately 

two years ago, both the U.S. Senate and the U.S. House of 

Representatives began drafting legislation designed to protect 

grid reliability and to defend energy infrastructure 

from cyber and physical attack. New drafts of those proposals, 

strikingly familiar in their structure and wording 

to those of two years ago, appeared in Congress earlier this 

year, and were widely discussed in May and June, as this 

issue of Intelligent Utility went to press. In both cases, it was 

ILLUSTRATION BY ABBY ORLANDO



16 

clear that the federal government intends to redefine FERC’s 

powers and control over both the bulk power system and 

“defense critical electric infrastructure” (defined, essentially, 

as anything not currently covered by the legal definition of 

the bulk power system)—even if only for 

the purposes of “protect(ing) the bulk 

power system and electric infrastructure “ 

critical to the defense of the United States 

against cyber security and other threats 

and vulnerabilities” (according to the Grid 

Reliability and Infrastructure Defense, or 

GRID, Act proposed by the U.S. House of 

Representatives). 

The discussion draft proposed by the 

Senate has similar intent. 

In this corner 

Understandably, this has created quite 

a stir, primarily focused on the roles 

of FERC and those of NERC, and the 

question floating above it all is quite simple: Why is FERC 

being granted new, overriding powers, flying in the face of 

the established role of the ERO? 

In a letter to U.S. House Energy and Power Subcommittee 

chairman Ed Whitfield (R-Ky.) and Ranking Member Bobby 

Rush (D.-Ill.), American Public Power Association (APPA) 

president and CEO Mark Crisson said that, while the APPA 

supports new authority for FERC to issue emergency 

orders in the event of a grid security event, provisions in the 

GRID Act giving federal regulators increased authority to 

regulate electric industry cyber security vulnerabilities are 

“unnecessary and overly broad.” 

Further, he wrote, the vulnerabilities provisions of the 

GRID Act “could allow FERC to rewrite the entire mandatory 

and enforceable standards the electric utility 

industry has worked on for nearly eight years.” The GRID 

Act, as drafted, would also allow the commission to enact 

standards without first consulting with utility experts on 

reliability efforts, he noted. 

Gerry Cauley, NERC’s president and CEO, says that, 

while government authority to deal with cyber emergencies 

is needed, and NERC stands ready to assist in responding 

to identified grid security threats, there are definite issues 

with the GRID Act, as drafted. In his written presentation 

to the House Energy and Power Subcommittee at the end of 

May, he said: 

“NERC’s mission is to ensure the reliability of the North 

American bulk power system. This responsibility encompasses 

the security of cyber assets essential to the reliable 

operation of the electric grid. NERC works with government 

agencies, industry and consumers to support a coordinated, 

comprehensive effort to address grid cyber security. NERC’s 

FERC-approved critical infrastructure protection (CIP) 

reliability standards are one of only two sets of mandatory 

cyber security standards in place across the critical infrastructures 

of the United States today. In addition, NERC’s 

three-level Alert system informs 

industry and recommends preventative 

actions to address 

imminent and non-imminent 

cyber threats and vulnerabilities. 

“These existing practices should 

be enhanced, not pre-empted, by 

grid cyber security legislation.” 

(Current procedures) 

do not provide an 

effective and timely 

means of addressing 

urgent cyber 

or other national 

security risks. 

REGULATORY INTEL 

In the opposite corner 

On the other side of the argument 

stands Joseph McClelland, 

director of the FERC Office of 

Electric Reliability. In a presenta- 

” 

tion similar to his Senate testimony, 

McClelland told the House 

subcommittee that the procedures used by NERC, while 

“appropriate for developing and approving routine reliability 

standards ” ... can be an impediment when measures or 

actions need to be taken to address threats to national security 

quickly, effectively and in a manner that protects against 

the disclosure of security-sensitive information.” 

The current procedures used under Section 215 for the 

development and approval of reliability standards, 

McClelland said in written testimony, “do not provide an 

effective and timely means of addressing urgent cyber or 

other national security risks to the bulk power system, particularly 

in emergency situations. Certain circumstances, 

such as those involving national security, may require immediate 

action, while the reliability standards procedures take 

too long to implement efficient and timely corrective steps.” 

Ignoring the elephant 

Interestingly enough, the other elephant in the room 

remains unaddressed by most parties to the discussion: the 

expansion of control—no matter whose—to include not 

only the bulk power system as currently defined, but also 

“defense critical electric infrastructure.” 

Distribution systems were intentionally excluded from 

the jurisdictions of both FERC and NERC in Section 215 

of the FPA, as Cauley pointed out in his Senate Committee 

on Energy and Natural Resources testimony earlier in May. 

“If the intent is to expand the scope of authority for electric 

system security into distribution systems, this is a critical 

issue requiring involvement of the states, and also calls for 

consultation with asset owners and operators and other 

stakeholders who should be included in such a process,” he 

told the committee.

Establishing 

coherent policy 

+ + Ex-FERC commissioner Suedeen Kelly 

provides transmission insight 

By Phil Johnson 

ON MAY 19, 2011, THE FEDERAL ENERGY 

Regulatory Commission (FERC) issued a Notice 

of Inquiry, or NOI, asking industry opinions on how to 

approach future transmission incentives. (FERC in 2006 

had issued Order No. 679, relating to incentives for transmission 

projects.) 

The FERC NOI uses the phraseology, “given the significant 

changes in the electric industry and FERC’s experience 

in applying Order No. 679.” 

We asked former FERC commissioner Suedeen G. 

Kelly—who served on the commission from 2003 through 

2009, and is now an energy-industry specialist at the 

Aclara leads. 

Aclara understands that utilities need to do more than 

collect data. We are driving a future that integrates 

AMI, SCADA, distribution automation, and more into 

an Intelligent Infrastructure with the capability for 

communications and control. With the strength of 

our solutions for electric, gas, and water utilities, we 

understand your vision. With our network we will take 

you there. Aclara Leads. 

Washington, D.C.-based law firm Patton Boggs—for some 

transmission insights. 

INTELLIGENT UTILITY What factors should FERC consider 

in evaluating an application for transmission buildout 

incentives? 

KELLY It depends on the objectives. When the commission 

announced Order 679 in 2006, it was responding to the 

Energy Policy Act of 2005, which authorized the commission 

to provide incentives for transmission. 

Frankly, the commission couldn’t reach a consensus in 

Order 679 about what the goal of transmission incentives 

should be. So what the commission passed was an order that 

simply didn’t answer that question. Effectively, what FERC 

was saying is, we’ll work this out on a case-by-case basis. 

But really, there still isn’t a coherent policy that’s come 

out of it. So that’s what this current commission seems to be 

trying to accomplish. 

INTELLIGENT UTILITY What obstacles are faced by transmission 

developers, and what incentives are best suited 

to addressing those obstacles? 

KELLY Again, it all depends on each project. 

What’s interesting to me is that the industry has changed. 

“We need partners that 

understand our vision 

for the Smart Grid.” 

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18 

When Congress passed the Energy Policy Act of 2005, it was 

a statute that had actually been negotiated in about 2003. So 

the provisions in that statute were dealing with the world as 

we knew it in 2003. 

There was concern that not enough capital was going 

into transmission relative to generation. Also, the concern 

was that we needed 

enough transmission 

to ensure that 

these new competitive 

generators could 

get to market, and we 

were seeing “congestion”—or, 

in other 

words, not enough 

transmission. 

But by 2006, when 

the commission implemented 

its order, 

we were starting to 

get more build-out 

of transmission. So 

the debate was, “Do 

we need incentives 

now for building out 

transmission?” And 

some commissioners 

thought, “Yes,” and some commissioners said, “It should be 

tailored to different kinds of projects.” 

As we’ve seen this incentive program implemented from 

2006 till now, the industry has changed even more. The new 

public policy issue is transmission for getting to new renewables, 

to reach renewables and bring them to market. 

INTELLIGENT UTILITY How should the commission consider 

changes in cost estimates? 

KELLY The question is: When a utility says it’s going to cost 

$800 million to do this transmission project, should the 

commission use that cost estimate? 

If the commission then awards “construction work-inprogress”—allowing 

the utility to start recovering investment 

costs while construction proceeds—should the commission 

hold the utility to the cost estimate as a cap, as an 

alternative way of containing costs? 

The argument on the other side is: If that’s the approach 

the commission takes, everybody’s going to say, “It’s only 

an estimate—you never know how much it’s really going 

to cost.” So if that’s the commission’s policy, you’re going to 

send a signal that people should highball the cost estimates. 

INTELLIGENT UTILITY What other factors should the 

commission consider in implementing the law? 

REGULATORY INTEL 

KELLY We have to ask: What’s the commission’s goal 

going to be? 

Should the commission look at a project and say, “How 

risky is this? How hard is it to get permits? How difficult 

is it to build? Should we give incentives to help overcome 

particular barriers and difficulties associated with the 

particular project? Or do we look at what the project is going 

to accomplish from a public policy perspective?” 

In other words, is this—from a public policy perspective— 

the kind of project we want to incentivize or maybe even 

reward? Say, reaching renewables, or bringing in Canadian 

hydro, or building a tie-line to Canada, or a project that has 

the potential to interconnect the three grids. 

Or a third possible way the commission could approach 

this is the way it approaches the building of natural gas 

pipelines, which is to say, “It’s all important—the build-out 

of pipelines is an infrastructure we want to encourage.” So 

the commission could say, “At this stage in the evolution of 

our grid, we just need more transmission, and we want to 

encourage it. So we’re going to give incentives to every 

transmission project.” 

INTELLIGENT UTILITY How do you view future electricity 

transmission—in 2015, or 2020? 

KELLY It has to do with, “Where are we headed?” We 

usually build transmission because we need more transmission. 

But if we don’t 

need more generation 

or need to move genera- “ The new public policy 

tion from one place to 

issue is transmission 

another, we don’t need 

more transmission. 

for getting to new 

Having said that, 

however, there are states 

renewables, to reach 

that are pursuing renewable 

portfolio stan- 

renewables and bring 

dards: Texas, California, 

Colorado, New England 

them to market. 

to an extent, New York 

” 

to an extent are pursuing 

bringing new generation on line. And we are also seeing 

the potential for replacement of existing generation with 

new generation. So we will need transmission. 

INTELLIGENT UTILITY Is there one point you’d like to 

make that we haven’t discussed? 

KELLY The one point I’d like to make is that achieving 

a consensus on what we are trying to accomplish with 

transmission is, first, the key to a good transmission policy 

and, second, the most difficult thing to achieve. 

Phil Johnson is a freelance writer and speechwriter.

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20

ILLUSTRATION BY MELISSA DEHNER 

Distributed 

Generation Redux 

Solar solutions 

+ + Distributed load or 

microgridding—or both? 

By John R. Johnson 

BORREGO SPRINGS, A PROGRESSIVE DESERT 

community located in San Diego County, is well 

known as a year-round center for astronomy research. 

In fact, the small town situated on the edge of the Anza- 

Borrego Desert State Park was designated as California’s first 

International Dark-Sky Community to keep the star gazing 

sky as clear as possible. 

When the community isn’t looking to the nighttime 

stars, its residents are embracing the sun—specifically, the 

vast potential from solar power. San Diego Gas & Electric 

(SDG&E) recently received a $10 million grant from the 

U.S. Department of Energy and the California Energy 

Commission to build a complex micro-grid project based 

in Borrego Springs. 

Riding it through 

Under clear desert skies, SDG&E will test and deploy various 

smart grid technologies including energy storage, smart 

meters, energy-management systems and integrated renewable 

energy generation. 

The goal of the three-year project is to demonstrate how to 

maintain reliability in a more complex grid, leverage distributed 

resources to benefit the community and electric system, 

enable more active participation by smart-meter-enabled 

customers, and maintain power—or “ride through” an outage—even 

when the larger grid is experiencing problems. 

In addition, the federal funding will help to install solar 

power generators at homes and small businesses, coordinate 

new peak load management technology, improve overall 

power quality and integrate and remotely control distributed 

generation storage devices to allow access to electricity 

in emergencies. The project will also provide research on the 

potential impact of electric car charging on the grid. 

OMS/DMS laboratory in action 

“This project is a ‘laboratory in action,’ where we can see, 

on a small scale, a version of the smart grid all the way from 

customer-generated solar power, to battery storage, to automatic 

power restoration,” said Tom Bialek, chief engineer of 

the smart grid for SDG&E. 

Bialek said that SDG&E will also use the project to 

integrate outage management system/distribution management 

system (OMS/DMS) into the microgrid operations. 

The utility will also have the ability to intentionally island all 

Borrego Springs customers in response to system problems 

like outages. 

A microgrid is essentially a small version of an electric 

grid that utilizes distributed energy resources and state-ofthe-art 

controls and equipment to enhance grid operation 

enough to achieve a 15 percent reduction in feeder peak 

loads, while increasing reliability. Ideally, microgrids promote 

energy independence within a certain community, 

potentially allowing ratepayers to be totally sustainable and 

exit the larger utility grid in favor of power from their own 

renewables like solar and wind. 



22 

“ 

Challenges driven by legislation 

Driving the Borrego Springs project is California legislation 

that requires the state’s utilities to buy 20 percent of their 

power from renewable sources like solar and wind. That percentage 

increases to 30 percent by 2020. Integrating the new 

energy sources, as well as energy produced by homeowners 

with solar panels, can be a challenge for utilities, which is 

why the Borrego Spring project exists. 

Assuming that hurdles like 

Residents are energy storage can be ironed out, 

the microgrid project could have 

embracing the the potential to provide 15 MW 

of electricity, enough to power 

sun — specifi- the entire Borrego Springs community. 

At present, 75 homes 

cally, the vast have installed solar power in the 

community, with a cumulative 

potential from output of just under 800 kW. 

While the solar conversion 

solar power. 

growth rate for Borrego has not 

” 

been forecasted, the California 

Energy Commission’s growth 

forecast for the state calls for solar installs to grow 37.5 percent 

this year and next. There are currently about 200 MW 

of solar generation in the California grid. 

Coping with the challenges 

Like most utilities, SDG&E is trying to cope with the many 

challenges of smart meter deployment, like how to roll out 

smart meters and capture customer engagement, how to best 

plan for distributed resources like solar that can be intermittent 

at best, especially during San Diego’s foggy months, how 

to convert on a 10-year smart grid plan that includes items 

that are not even possible yet technology-wise, and how to 

best evaluate the slew of new technologies headed to the utility 

market. The purpose of the Borrego Springs microgrid 

project is to examine all of those issues and much more. 

For example, during the spring, San Diego is hampered 

by two months of thick fog, which creates havoc with the 

utility’s ability to process power generated from rooftop 

solar systems. 

“If you know anything about San Diego, we have May Gray 

and June Gloom coastal fog which travels pretty far inland,” 

said Bialek. “It tends to burn off by noon, but you get little 

pockets where there are no clouds, and output of PV systems 

increases dramatically. Then the fog closes back in, creating 

significant power fluctuations which our voltage regulation 

equipment tries to keep up with during those short periods 

of time. So there are issues associated with penetration of PV 

and we’re trying to be pro-active about that.” 

While the integration of all the different IT components 

and communication systems represents one of the larg- 

DISTRIBUTED GENERATION 

est challenges in the project, “the real challenge is looking 

at some of the smart concepts around customer empowerment 

and trying to get customers to participate in the 

smart meter program,” said Bialek. “Based on their participation 

level, then you modify the output of generators to 

compensate for demand.” 

Multi-technology testing ground 

So far, smart meters have been deployed to all 2,800 customers 

in Borrego Springs. SDG&E is 98 percent complete in 

rolling out 1.4 million smart meters to its entire customer 

base. Studies show that smart meters can help homeowners 

to save between 5 and 15 percent on their utility bills 

by conserving energy. 

At present, two 1.8 MW diesel generators are being retrofitted 

and will be installed at the substation in August for factory 

testing. SDG&E has completed an RFP for energy storage 

components, with expectations that energy storage will 

be installed during the second quarter of 2012. Homes with 

existing solar and those that add solar during the course of 

the project will be equipped with home solar generators. The 

entire microgrid project is scheduled for completion during 

the first quarter of 2013. 

The Borrego Springs project will also serve as a test ground 

to define the future technologies needed to effectively run a 

smart grid and integrate renewable energy sources. 

Today, smart meter technology alerts a utility when a 

customer’s power is disrupted. Eventually, technologies 

will become sophisticated enough to send alerts when a 

system is about to fail, and remedy a potential 

problem before it occurs. During this 

self-healing process, grid switches will 

automatically re-route power to 

restore an outage without any 

human intervention. 

For now, that remains a challenge. 

For example, in the smart 

grid deployment plan filed 

recently by SDG&E, technologies 

do not exist yet to support 

many of the concepts included for 

2015 and beyond. Bialek says that 

commercially available energy storage 

options, equipped with the functionality 

to run certain types of protocols or scenarios, 

are still a couple of years away. 

“There are a lot of concepts there,” said Bialek, “but not 

a lot of hardware or software yet to provide a solution. 

That’s a major challenge for a utility like us. That’s why the 

Borrego Springs project is so important.” 

John R. Johnson is a Boston-based freelance writer covering 

wireless and RFID technology, as well as alternative energy topics.

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24 

Utility 

Mobility 

Integrating 

mobile 

solutions 

+ + Utilities describe their challenges, 

successes and lessons learned 


AN INTEGRATED MOBILE WORKFORCE MAN- 

agement platform—tying in field management, 

outage management, customer information, geospatial information 

and other systems—provides utilities with the 

ability to transform the way field work is performed. It can 

improve restoration times, increase customer satisfaction 

and increase overall productivity, thereby lowering cost. 

These were the goals of the mobile dispatch project launched 

by Exelon Business Services’ two electricity distribution 

companies, ComEd and PECO. The project was featured 

in the January/February 2011 issue of this magazine, and a 

subsequent Intelligent Utility Realities webcast in April took 

a deeper dive into this project, as well as new mobile workforce 

management projects implemented by JEA (formerly 

Jacksonville Electric Authority) and Vectren Corporation. 

The challenges faced were different in scope, the 

successes notable, and the lessons learned definitely worth 

sharing here. Edited for length and style, panelists Jackie 

Scheel (manager of water and sewer customer service responses 

for JEA), Mark Browning (director, IT ComEd 

Solutions, Exelon) and Rich Schach (vice president of 

energy delivery, Vectren) offered numerous utility insights. 

A few are shared here. 

ILLUSTRATION BY KEVIN HOWDESHELL



26 

I asked about the cultural changes associated with adding 

new technologies to the mix in the field, and the types 

of technologies being incorporated with the field services 

groups at each utility. 

SCHACH It’s kind of interesting to watch. Like all utilities, 

and probably a lot of industry, we’ve got an aging workforce 

and we’re going through quite a transition with retirements 

and the like. What’s interesting, and it’s probably just a sign 

of the times, is that as we bring in these people to our organization 

who have had a little more access to the iPhones 

and the games and things that this generation is used to, 

not only are we not seeing a cultural issue, but we’re seeing, 

“Why can’t it do this?” or “Why can’t it do that?” The whole 

world is changing around us, and we’re actually getting in a 

generation of folks that not only find it easier to use, but also 

are helping us find ways to make it better. 

Now, having said that, we still have a considerable workforce 

that has been around for a long time and we spend a 

lot of time trying to ensure that we keep their training up to 

speed. We are providing a lot more communication about 

what the value is and trying to have them recall what they 

used to do compared with what they do today. What we’re 

seeing is that even those folks who at the beginning were just 

dead set against a laptop in the truck, I’d venture to stay that 

at least 80 percent are more than happy to have it and would 

be upset if you took it away. 

SCHEEL Historically, prior to 2007, we used some type of 

Toughbook. Sometimes, this is where you ask, okay, if you 

come from nothing, then you can introduce folks to anything 

new. We did try, and then when we went to make the 

change to what are we going to use in the future, we tried the 

PDAs. The folks did not like them: they said they were too 

small, they couldn’t see them. 

The field worker was 

provided the same 

level of functionality 

and capability that 

an office worker 

in our environment 

would have. 

MARK BROWNING 


For me as management, I love the PDAs. But they did not 

like them. We even tried the tablets. I have to give kudos to 

our IT department. They said, okay, here’s what you have; 

take them and use them. But we voted on just a regular laptop. 

You can buy three laptops versus one Toughbook, and 

not all the trucks are so rough that they require a Toughbook. 

Now as far as field services, which is where I came from, I 

would strongly encourage the PDA if you can. But we have 

not engaged our employees enough. They are a little resistant 

to it, and right now, we’re not pushing that venue. We just 

use regular laptops with aircards that go into base mounts 

installed in the vehicle. But I would love to use PDAs. If it 

could start out that way, I would never give another option. 

BROWNING We started out thinking that we were going to 

deploy a lot of different form factors, a lot of different tools. 

Early on in the project, we quickly realized that the majority 

of users viewed the tool as something that was going to 

remain in their vehicle and that they wouldn’t be carrying it 

around. And it was really the taking it out of the vehicle and 

using it in various ways that we thought—in terms of collecting 

information in substations, making rounds and the 

like—would drive the need for different form factors. 

But we didn’t see that big push to drive to multiple form 

factors. So, we really took a one-size-fits-all approach for 

the project, and now, almost two years post-project, we’re 

starting to see maybe a revitalization of this drive for new 

form factors. I view it as a maturity and an evolution of the 

technology. The ruggedized laptop in the vehicle is probably 

something that solves 80 percent of our business problems, 

and now that 20 percent is driving the need to start to look 

at different form factors, in the form of smart phones and 

PDAs, that maybe synch with the device to go out, collect 

some form information and come back and sync with the 

vehicle’s MVT and push the information back up. So a lot of 

evolution, I think, is going to occur there over time. 

I asked each panelist about guiding principles or key lessons 

learned with their deployments. Here are a few of 

many that were discussed. 

BROWNING We approached this project as an extension of 

the edge of corporate network. This is an important piece in 

that we did not set any limitations or boundaries over what 

the field worker could do. The field worker was provided 

the same level of functionality and capability that an office 

worker in our environment would have. A fully enabled 

Web browser would allow them to leverage the corporate 

intranet and the Internet to perform their various work 

functions. And this was a key component that I think really 

helped our project gain traction with the field workers. It 

demonstrated trust in the field workers, trust that management 

had in their ability to use the tools, and it gave them 

an opportunity to look at how they could do their job in

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28 

a way that was most effective for them versus how I think 

management and the project team might have viewed how 

they would use these tools. 

And then finally, with deploying a mobile solution 

to 3,000 users who are all mobile, constantly changing, 

moving around, a lot of tools and technologies need to be 

put in place around software management and software 

distribution to keep the platform current, secure, and up to 

date at all times. 

You’ve got to test 

each one of your 

field activity types 

and let it write back 

to the system to 

see how it’s going 

to come across. 

JACKIE SCHEEL 

SCHEEL I’m from the business side, but sometimes in the 

IT world, people say, “How important is testing?” Well, you 

can never contradict or even contemplate what the system’s 

going to do, so you have to test each one of your scenarios. 

You’ve got to test each one of your field activity types and 

let it write back to the system to see how it’s going to come 

across. A lot of testing is what people seem to want to cut out 

of their timelines, and I highly recommend you do not cut 

your scenario testing out. 

Also, a major factor to having a successful mobile workforce 

unit is to get your front line employees engaged and 

ask them exactly what it is that they want to see or they don’t 

want to see. They’re the ones who are going to be using the 

system the most. When we added the meter service agency 

on [Ed. Note: JEA has been building its mobile workforce 

management platform in stages since 1988], we more than 

tripled the number of users. We added 200 users, and I will 

tell you one of our lessons learned here was, during the testing, 

during the project, we did as much load testing as we 

could, but what we did not realize was that most of these 


users would all be signing on at the same time. So what we 

did realize was that, at about 7 a.m., we had about 400 users 

hitting the machine. So we had to go back to our IT department 

and add a couple of different servers. 

We called it “morning sickness.” I would advise anyone 

that, when they do their testing and they do their load testing, 

they consider when and how many users will be on the 

system at the same time. 

SCHACH We spent a lot of time upfront establishing the 

right data into the tool, and that’s proven to be just a huge 

part of the success for Vectren. We do a lot of work managing 

by performance metrics dashboards and what not. If the 

data’s not in there correctly in the first place, it’s tough to 

get buy-in from your field management. If they just don’t 

believe the original data, (then they won’t) believe the data 

the system’s now spitting out. We spent so much time early 

on that we’ve gotten buy-in, and now we can just move on to 

managing the actual work. 

Panelists also discussed changing business processes with 

the new mobile platform. 

BROWNING Another key piece of the project was really 

looking at taking our current manual business processes 

and looking at how they would be implemented with the 

new technology. We certainly didn’t want to take a current 

manual process, put technology around it, and still do it the 

same way. There was an opportunity to leverage technology 

and redesign the process and we tried to do that wherever we 

could. A big piece of this was focusing on handoffs between 

work groups and ensuring the right data got out to the field 

at the right time for each of our users. 

SCHACH Meter order management was my largest activity, 

and as such, we spent a lot of time trying to figure out 

how we could better manage that area. One problem we had 

was that our labor contract had originally, some years back, 

forced us to treat our various operating centers across our 

service territory as individual operating centers—everybody 

sort of did their own thing, if you will. 

The workers were tied to those areas or depots and they 

couldn’t cross boundaries, and it just didn’t make sense. You 

could have an emergency where somebody might live literally 

across the street and they were not allowed to work that 

emergency because of the labor issue. 

So once we were able to break that model through contract 

discussions, it opened the gamut of flexibility for us to 

then focus on this category of work. 

And finally, more keys to success, and overall benefits: 

SCHACH Since 2004, this cost category saved about $3 million. 

So, we’re operating at $3 million less than we would 

have then, and obviously that’s a number that’s going to continue 

on in the future and hopefully even get better. We’ve

© 2011 Enspiria Solutions, Inc., a Black & Veatch Company 

also improved the number of orders per FTE and, in some 

cases, multiple more orders per FTE. 

BROWNING Another key success factor during this project 

was around deployment. This was a program that was 

cutting across six departments across two companies. We 

wanted to ensure success by doing a slow roll, trying it with 

one group, piloting where we could, gaining learnings and 

experience from that group and then expanding to really 

build momentum. And that was something I think we found 

was very successful. So piloting, and soliciting feedback and 

incorporating that into the next phase was key to ensuring 

that anything that was working we build on and things that 

weren’t working so well we tried to address as we moved 

through the project. 

SCHEEL Everything is tied in [with regard to vehicle tracking]. 

In fact, we’re in the middle of a GPS project, too, that 

will tie everything back in together into this one. We do have 

the vehicles tied into the laptops. We have to do that for anyone 

who lives in a hurricane area, for FEMA recovery. We 

have to be able to track the vehicle that went out there with 

the work order. I believe you could only do that with some 

type of workforce management. I don’t see how you could 

do that on a piece of paper. 

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32 

» COMMUNICATIONS NETWORKS 

No one size fits all 

+ + Network of networks requires 

combination of solutions 


THE DISCUSSION HAS LONG BEEN BREWING: SHOULD OUR 

smart grid networks be public, private or a combination of both? 

Within utility projects and deployments, we’ve seen very clearly that one size 

doesn’t fit all, no matter what the technology, software or system being implemented. 

Just as the smart grid is a network of networks, so, too, are the network 

needs within it. 

Dispelling myths 

But as the debate continues, the Utilities Telecom Council (UTC) opted to 

discuss the issues and dispel some myths in a February 2011 document titled 

“The Truth About Utility and Other Critical Infrastructure Industry Telecom 

Capabilities and Needs.” 

“CIIs (critical infrastructure industries) will ultimately choose to build their 

own networks or buy telecom services based upon technical requirements, costs 

and levels of service required. CIIs have and will continue to utilize others to 

provide telecom services for certain aspects of their operations and smart grid 

deployments based upon these criteria,” the UTC paper noted. 

Subtle issues at play 

Historically, the issues that have come up in the public/private network debate 

have centered around cyber security and standards issues. Public carriers point to 

the fact that they have already solved the very same issues utilities are now facing 

in both areas, and can offer both best practices and state-of-the-art technology. 

But while utilities may be exploring public networks 

in certain areas, such as distribution, the ar- 

One size doesn’t fit 

eas of transmission and generation still tend toward 

private networks, for a number of reasons. 

all, no matter what 

Regulatory structure also plays a part in utility 

network decisions. While in the United Kingdom, 

the technology, 

the regulatory structure really favors the public 

market, there is still a real incentive for utilities in 

software or system 

the United States to own their own networks, taking 

the private approach. 

being implemented. 

Hydro One chooses mesh solution 

As but one example, Hydro One Networks Inc. opted for the mesh network 

route for its communications. Owned by the province of Ontario and the province’s 

largest electricity distributor with a service territory land mass twice the 

size of the state of Texas (123,000 kilometers of distribution lines and a 640,000 

square kilometer service territory), Hydro One’s customer base of 1.3 million 

is a mix of urban, rural and remote customers, some accessible only by air, rail, 

boat or snowmobile. 

Based upon its unique needs, the 

distribution utility chose a two-way 

mesh radio network that would allow 

it the flexibility to accommodate cellular, 

broadband or fibre WAN backhaul 

capability. 

More specifically, Hydro One’s AMI 

solution architecture is comprised 

of a two-way self-healing mesh radio 

network based on the global 2.4 Ghz 

IEEE 802.15.4 standard. The solution 

provides the utility with the futurelooking 

flexibility to accommodate 

cellular, broadband, or fibre WAN 

backhaul capability. 

By integrating standards-based 

mesh radio and WiMAX wireless 

technology, the utility will be able 

to implement a broad spectrum of 

initiatives, including distribution 

automation, outage management, 

theft detection, remote disconnect, 

mobile work dispatch, twoway 

communication home thermostats 

and real-time energy monitors, 

and more. 

Avista chooses 

broadband route 

Others have gone the private route, 

as well. In Pullman, Wash., Avista 

Corp.’s smart grid demonstration 

project will incorporate an advanced 

metering infrastructure 

(AMI), smart grid communications 

and distribution 

automation devices 

using a private wireless 

broadband communication 

network. According 

to Jim Corder, Avista’s 

director of IT infrastructure, 

the choice will allow 

the utility to bridge 

the two network technologies 

while reducing the number 

of devices the utility has to manage 

and support. “We’re expecting 

the network will meet or exceed all 

of our performance requirements for 

the initial smart grid applications,” 

Corder said.

Texas co-ops opt for public 

communication with homes 

On the other side of the coin, public 

networks are also being used by utilities 

to manage certain two-way communication 

aspects of the evolving grid. 

According to a recent EPRI white 

paper, “Communication Modularity: 

A Practical Approach to Enabling 

Demand Response,” an important part 

of the smart grid vision is “enabling 

communication-connectedness with 

residential devices so that they can be 

informed of grid conditions, including 

energy price, critical peaks and other 

curtailment events.” Communication 

to intelligent devices, the paper’s authors 

go on to say, rather than cutting power 

off with a remotely managed switch, 

“provides more flexibility for consumers 

and allows manufacturers to innovate, 

discovering creative ways to maximize 

energy savings while minimizing 

user inconvenience.” 

Texas-based Bluebonnet Electric Cooperative and Pedernales Electric 

Cooperative, in partnership with the Lower Colorado River Authority, piloted 

a public carrier solution using 3G and 4G LTE networks to provide real-time 

communication from their consumers’ electric meters to a central data center, 

empowering Central Texas residential and small commercial members to actively 

monitor and control their energy usage through a smart home area network 

(HAN) installed within their homes or businesses. 

Two-way communication is critical to enabling viable load management while 

still enabling consumers to maintain control of their energy use. Both co-ops 

were able to combine third-party demand response technology with a public 

carrier solution, leading to the potential for a broader-scale use. “Our tests on 

the technology during the winter load events showed the enormous potential 

of a load management program that benefits both consumers and utilities,” 

Bluebonnet CEO Mark Rose said upon completion of the pilot project. 

No either/or necessary? 

Riding the wave of diverse needs, some vendors have opted for both public and 

private solutions for utility clients, depending upon specific yet diverse needs. 

With approximately 3,200 utilities across the country comes the potential 

of 3,200 individual needs. As standards continue to be set, these standards will 

allow utilities to make their own decisions based on their business cases and 

their individual needs. 

In fact, many vendors and utilities alike are no longer seeing communications 

networks as an either/or solution. One major player explained it this 

way: “I believe it’s a blended solution between private and public networks. 

Communications consists of a network of networks stretching across all seven 

domains. The bottom line? I believe there’s a place for both technologies.” 

Utilities, he said, need to look at a variety of factors when deciding what solution 

is best, and for what uses. First, it’s important to look at the actual use case. 

Add into the decision the cost of the particular application, the regulatory environment, 

latency and through-put, availability and reliability of the solution and 

cost and longevity, and the answer is complicated and utility-unique. 

Some utilities have opted to use both public and wireless, with collection 

points served by both, using the private network as the primary network (especially 

with regard to the “last mile” to the meter), and the public network as the 

failsafe, or the backhaul network. 

Capx issues play a role 

Investor-owned utilities (IOUs) looking for rates of return might not opt 

for public network solutions in which the recurring expense of the public 

network passes through to the consumer. Large IOUs, in the current regulatory 

atmosphere, are motivated to be very conservative, based on their regulatory 

structure. As well, the historical culture of 

On Sept. 1, the Intelligent the electric utility industry has been one of 

Utility Reality webcast “build it, own it, manage it.” 

series will address the public/ 

Alternately, small utilities might find the 

private network question with 

three utilities in the trenches, public network solution to be the one that 

identifying challenges, 

best fits their business cases. Running a 

opportunities and lessons network is complicated, especially with 

learned in their deployments. 

a minimal number of employees already 

stretched in other responsibilities. 


GRID(UN)LOCK 


34 

Nashville Electric 

Service pursues 

voltage conservation 

+ + TVA’s new “demand charge” 

calls for “solution on a shoestring” 


THIS STORY IS A GREAT EXAMPLE OF WHY “SMART GRID” 

means vastly different things to different people. It also illustrates 

why challenges and solutions for electric utilities tend to be utility- and 

location-specific. 

The Nashville Electric Service (NES) is employing what Vic Hatridge, vice 

president and CIO, calls a “solution on a shoestring” to deal with changes in 

how the Tennessee Valley Authority (TVA) charges for its wholesale electricity 

to municipalities in the Valley. 

Energy charge vs. demand charge 

TVA has traditionally levied an “energy charge” and a “demand charge” for 

commercial and industrial (C&I) customers within NES’ service territory. That 

means those customers pay for their electricity use (energy charge) and also pay 

a demand charge based on their peak 

use during a 15-minute interval 

during a given month. 

That demand charge, of course, 

goes to pay back TVA for capital expenditures 

needed for the capacity to 

meet those peak electricity demands. 

Thus, NES’ larger C&I customers have 

always had demand meters that take a 

single high-demand reading to gauge 

their peak electricity consumption. 

Residential peak demand 

charge problematic 

Starting in April 2011, TVA began 

to bill NES and its other distributors 

a demand charge based on the peak 

usage during a month for all residential 

customers combined. This created 

a problem for NES and all other 

distributors because they were being 

charged for peak demand but had no 

way to equitably recover these costs 

from residential customers. 

Smart meters on every home could 

provide a means to bill each residential 

customer for energy charges based 

on their time-of-use (TOU) demand

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36 

“ 

and/or demand charges reflecting their peak use, but that’s too expensive for this 

municipal, distribution-only utility with about 360,000 customers. (Although 

modest on paper, that profile makes Nashville one of the nation’s top dozen 

municipal utilities, by size.) 

Shoestring solution 

Instead, NES will implement a voltage conservation program on a systemwide 

basis to reduce peak demand and, therefore, mitigate the impact of demandbased 

wholesale rates on residential customers. The American National 

Standards Institute (ANSI) standard calls 

for 114 to 126 volts per residential end-user. 

We need consistency 

During peak load, NES will narrow that range 

to about 116-120 volts. It will use smart meters 

and predictability of 

as “continuous voltage sensors” at key sample 

points on every circuit. 

revenue and profit 

In this manner, NES can reduce its cost for 

peak-time energy use without the need to 

so we can bill our 

install a smart meter at every home in its entire 

service territory. Ultimately, the utility would 

customers equitably. ” 

like to install smart meters on every home 

to ensure that every customer’s voltage stays 

within the ANSI standard and to achieve the many other benefits that smart 

meters provide. TVA and NES are cooperatively involved in this solution, which 

should be fully operational by this time next year. 

“Over the past 20 years, our retail rates have been what they call ‘end-use rates,’ 

which means that we paid TVA for wholesale power 

in the same way we billed for retail power,” Hatridge 

told me. “For example, retail customers paid a flat 

rate per kilowatt hour, so we reported to TVA how 

many kilowatt hours we sold to retail customers and 

paid TVA a flat charge per kilowatt hour for that 

power. For those large commercial and industrial 

customers that we billed for a demand charge, we 

reported that customer’s demand to TVA and paid 

TVA for that demand.” 

For residential customers, because NES only collected 

and passed through costs for energy consumed 

in kilowatt hours, NES received a guaranteed margin. 

Changing the face of the Tennessee Valley 

“What happened to us, as of April 1, is changing the 

face of the Tennessee Valley,” Hatridge said. “TVA 

is now going back to an old system of charging us 

demand charges for the energy we sell to residential customers. 

“This puts us at risk because we are billing residential customers at a flat rate 

per kilowatt hour but our wholesale cost for that power will vary. If we happen 

to have a really hot day near the end of the month, like we did in May 2011, our 

wholesale power bill from TVA shoots up much more than what we bill to our 

residential customers. We are concerned about how such an unpredictable profit 

margin will affect our financial stability.” 

In effect, NES will use a smart grid technique—in general, distribution optimization, 

in particular, voltage conservation—to manage retail rates to reflect 

wholesale rates from TVA. 

“We need consistency and predictability 

of revenue and profit so we can 

bill our customers equitably for what 

they use,” Hatridge said. 

Cost-effective 

win-win solution 

These changes may mean that NES 

sells less electricity overall, though 

ideally it would like to maintain the 

amount it sells, just shifting consumption 

to off-peak hours. 

“On a hot summer day when we’re 

trying to conserve power, we can actually 

turn down your voltage to, say, 

116 volts,” Hatridge said. “This won’t 

affect the performance of a customer’s 

electrical equipment, but it will reduce 

peak load. It will maintain a more 

consistent margin for NES and it will 

save the customer money because 

they will consume slightly less energy. 

We’ve prevented a brownout by making 

a slight adjustment in voltage that’s 

within the acceptable range. 

“We think this is a very cost-effective 

solution,” Hatridge concluded. 

“We can achieve some very significant 

reductions in peak energy demand at a 

reasonable cost and without requiring 

customers to change their energy 

usage habits.” 

This article first appeared in Intelligent 

Utility Daily.

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END OF THE LINE 


38 

A new attitude 

toward energy 

consumption? 

+ + Deloitte study suggests new customer diligence 

By Christopher Perdue 

AS UTILITIES LOOK FOR WAYS TO ENGAGE THEIR CUSTOMERS 

with new products and services, a new study from Deloitte suggests they 

may find an eager audience. The study, “reSources 2011,” conducted by Deloitte, 

polled 3,200 household decision makers and more than 400 business decision 

makers responsible for their company’s energy decisions or energy policy. 

Let’s take a look at some of the results of the study, and their implications 

for utilities. 

The study from Deloitte suggests the emergence of a diligent new attitude 

toward energy consumption in the United States. According to the study, 

52 percent of companies are working to lower their energy costs by 25 percent 

on average over the next two to three years, and 68 percent of consumers are 

taking extra steps to cut their electric bills because of the recession. 

Profound grassroots movement emerging 

The results of the study show American businesses and consumers are in the 

midst of “the birth of the resourceful energy user,” said Greg Aliff, vice chairman 

and U.S. energy & resources leader, Deloitte LLP. “We are seeing a profound and, 

in many ways, grassroots movement toward energy conscientiousness among 

businesses and consumers.” 

In addition to the almost 70 percent of consumers who said they reduced 

their electricity bills during the recession, 95 percent said they do not intend 

to increase their electricity use even 

as the economy improves. 

Energy management 

goals set by businesses 

Energy use at businesses also appears 

to be receiving renewed attention. 

Ninety percent of the companies 

polled for the study were setting 

specific goals regarding electricity and 

energy management practices, and 

nearly three-quarters of businesses 

now have goals related to reducing 

electricity cost and consumption 

and improving the efficiency of the 

buildings in which they operate. 

Furthermore, slightly more than half 

of companies have goals aimed at improving 

profitability through electricity 

reduction and nearly one-third of 

companies have goals to self-generate 

electricity through measures like 

installing solar panels. 

With utilities increasingly seeking 

to engage their customers with new 

products and services, the results of 

the study should be encouraging. And 

the proliferation of smart grid investments 

will provide a means to deliver 

and display consumption data directly 

to the customer. 

More energy use 

knowledge needed 

The news from Deloitte is encouraging, 

but I must admit to being a 

bit skeptical of some of the results. 

While 68 percent of consumers in the 

Deloitte study claim they are taking 

extra steps to cut their electric bills 

because of the recession, the reality is 

that annual residential kWh sales in 

the U.S. for 2010 were the highest on 

record according to the latest Electric 

Power Monthly report from the 

Energy Information Administration. 

This represents growth of more than 

6.3 percent from 2009. 

This discrepancy is telling, and 

could speak to the lack of knowledge 

that utility customers have about 

their energy use.

This lack of knowledge was somewhat 

evident in the Deloitte study. 

One of the questions asked whether 

the respondent was in a deregulated 

environment where more than one 

electric company competes for your 

business. Over 60 percent of consumers 

answered that they were not sure. 

Additionally, consumers did not 

seem particularly enthused about 

purchasing either a “smart energy 

application” (18 percent said “yes”) or 

paying a small amount for a meter or 

timer control system (25 percent said 

“yes”). But the youngest generation 

(“Gen Y”) was twice as likely as the 

oldest (“Matures”), with 33 percent 

of Gen Y saying “yes” to a small 

amount for a meter/timer control 

system and 16 percent of Matures 

saying “yes.” That would suggest that 

the wholesale behavioral changes 

around energy practices may indeed 

be a generational affair. 

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Community education a necessity 

These points provide a clear indication that utilities need to invest in a solid, 

on-the-ground community education. 

Utilities cannot become so preoccupied with the implementation of physical 

infrastructure that they do not think through the implications of new technology 

and products on customer relationships or the business process. And they 

should not wait for their smart meter deploy- 

ment to start the education push. Now’s the time 

to let customers know, in advance of the viral 

spread of misinformation by anti-smart-meter 

lobbying interests, what smart grid efforts are 

really all about. 

Further, utilities should not assume that 

customers know anything more than the basics 

of electricity as it applies to them, and make it 

easy for customers to obtain the information they 

need. Otherwise, they will go elsewhere, and fill 

the information void with whatever they can find. 

I hope Deloitte is right, and that we are seeing 

the birth of “the resourceful energy user.” But 

let’s keep in mind that there is still a lot of cus- 

tomer education that will be needed to supplement these new attitudes. Therein 

lies an opportunity. 

Christopher Perdue is vice president of Sierra Energy Group. 

Copyright © 2011 Clasma Events Inc.. The words and logos of Clasma, GridWeek, BuilConn, HomeConn, 

IndConn, GridWise Expo and ConnectivityWeek are trademarks or registered trademarks of Clasma International 

Corporation, all rights reserved. All other trademarks are registered to their respective owners. 

“ 

We are seeing a 

Advisory Major Board Partners & Major Partners 

profound and, in 

many ways, grass- 

roots movement 

toward energy 

conscientiousness.” 

For Information 

www.GridWeek.com 


4D 


40 

Location is imperative 

+ + Geospatial data is central to Hydro One smart grid 

By Nargis Ladha and Erik Shepard 

HYDRO ONE IS THE ELECTRICITY PROVIDER FOR A LARGE 

proportion of Ontario and serves approximately 1.3 million rural 

customers, with a service territory nearly twice the size of Texas, comprised 

of 17,771 miles of transmission circuits, 76,429 miles of distribution circuits 

and more than 2 million poles. 

Because of this large service territory, field inventory of distribution assets 

or conversion of paper maps was deemed cost prohibitive, and the geographic 

information system (GIS) has historically focused largely on transmission assets, 

with some tactical support for distribution assets (predominantly focused on 

new designs and maintenance of a simplified schematic power system model 

for grid operations). 

New topographical model for distribution assets 

Hydro One has regulatory requirements to field-inspect all distribution system 

assets on a six-year asset condition assessment cycle. At the initiation of the last 

cycle, in 2005, determination was made that for a marginal additional cost, field 

collection could also collect GPS location and asset attributes to form the foundation 

for constructing a GIS for distribution assets as well. GIS technicians perform 

post-processing on this field data to 

integrate network topology, resulting 

in a spatially and topologically accurate 

model for distribution assets. At present, 

more than 95 percent of the distribution 

system has been completed. 

The biggest challenge to leveraging 

the existing asset condition assessment 

program has been that the fieldcollected 

data used to construct the 

distribution model may be as much 

as six years out of date. Fortunately, 

Hydro One has current data, albeit 

with spatial accuracy and completeness 

challenges, in the tactical design 

and grid operations distribution 

GIS databases. 

The design database is spatially 

accurate, but only reflects new construction 

work and is not a complete 

representation of the network. The 

grid operations database is complete, 

but focuses on the network connectivity, 

excludes structures such as poles 

and pads, and is not spatially accurate. 

The consolidation of these two tactical

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4D 


42 

systems with the field-collected backbone is currently under way; this consolidation, 

together with completion of remaining feeders to be field collected, is 

scheduled and on target for completion by end of this year. 

In addition, Hydro One has nearly completed deployment of approximately 

1.2 million smart meters across the province. Each of these meters is also 

GPS-located, as are collectors and repeaters, and will be fully integrated into 

the distribution GIS in 2012. 

Driven by value 

While Hydro One has had a mature GIS for transmission 

assets for a number of years, until recently the expected 

return on the significant investment cost for distribution 

GIS was found to be less compelling. Hydro One is a valuedriven 

organization that continually reassesses the technology 

landscape to gain new efficiencies through innovation. 

With increased emphasis on the distribution business in line 

with smart grid initiatives, the strategic road map for GIS 

now comprises development of a spatially accurate distribution 

power system model and development of geospatially 

enabled enterprise asset management for distribution assets 

to form a core for emerging smart grid applications. 

In 2010, Hydro One initiated the Advanced Distribution 

System (ADS) project, an initiative in support of Ontario’s 

forward leading Green Energy Act. The ADS project builds 

on top of the successful smart meter deployment that is 

nearing completion, and seeks to implement a distribution 

management system and substation automation to enable 

the connection of distributed generation sources, including 

renewables. In 2010, business case development and RFP selection was undertaken, 

and Hydro One is currently engaged in 

designing and building the first project release. 

There has been a 

More data needed 

Many utilities are now finding that the data 

renaissance of field 

collected 20 years ago is not sufficient for smart 

grid, and there has been a renaissance of field collection to improve 

collection to improve the quality of geospatial assets 

represented in the GIS. Often, only basic attribution the quality of geoon 

assets deployed in the field has historically been 

collected—in some cases, only what was required spatial assets repre- 

to drive automated mapping and facilities management 

programs. 

sented in the GIS. 

GPS accuracy has also significantly improved with 

higher precision collectors at lower price points. 

Because Hydro One deferred its investment in distribution GIS, significant investment 

cost savings have been realized by only doing it once. In addition, evaluation 

of required data completed by the selected distribution management system 

(DMS) vendor found that “Hydro One’s initial data availability, accuracy (for DMS 

data model validation) and completeness is well above the industry average.” 

Populating distribution data 

DMS data will initially be populated by five key systems: network topology from 

the GIS, selected customer and load information, power system equipment 

characteristics, protection and control 

settings, and connectivity to the transmission 

system. While each of these 

data elements is critical, accuracy of 

the power systems model represented 

in the GIS directly determines the ability 

of the DMS to produce accurate 

results from power utilization and 

power quality applications. 

To ensure data currency, completeness 

and accuracy, Hydro One is also 

completing as part of the ADS initiative 

an assessment of distribution data 

change control processes to ensure 

that all data sources are maintained, 

and updated proactively according to 

business triggers rather than reactively 

when problems occur. These recommendations 

will lead ultimately to 

implementation to protect Hydro 

One’s significant investment in source 

data for the DMS. 

Hydro One’s investment in geospatial 

technology directly supports 

and is a key dependency for the success 

of the ADS project as well as a 

number of other strategic initiatives. 

The approach currently being taken 

to perform full field inventory, to 

consolidate legacy tacti- 

cal GIS systems, and to 

formalize and optimize 

distribution data change 

control policies and 

procedures will ultimately 

support Hydro 

One’s strategic goals as 

a geospatially enabled 

intelligent utility. 

Nargis Ladha is manager 

of geospatial systems 

and technology projects 

at Hydro One, and is 

responsible for setting strategic direction 

for GIS and coordinating corporatewise 

initiatives. 

Erik Shepard, of Waterbridge Consulting, 

is supporting Hydro One’s Advanced 

Distribution System (ADS) project as the 

project lead for the GIS data consolidation 

project and as the lead for the DMS Data 

Change Control workstream within the 

ADS project.

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CONNECTIONS 


44 

Cyber security 

requires organic effort 

+ + Strategist Annabelle Lee shares thoughts 

for utilities and regulators 


IN JUNE, INTELLIGENT UTILITY DAILY EDITOR-IN-CHIEF PHIL 

Carson held a wide-ranging discussion with Annabelle Lee, a technical 

executive for cyber security at the Electric Power Research Institute (EPRI). Lee was 

formerly a senior cyber security strategist at the National Institute of Standards and 

Technology (NIST), where she guided and coordinated the creation of the NISTIR 

7628: “Guidelines for Smart Grid Cyber Security.” 

Framed within the context of electric utility cyber security discussions ongoing 

at the time in the U.S. Congress (detailed in part on pp. 14-16), Carson’s interview 

spanned three days’ columns in Intelligent Utility Daily. We excerpt portions of 

those columns here. 

At the outset, I asked Lee: What can you tell utilities and regulators about 

implementing cyber security when standards remain in flux? Her candor 

was bracing. 

Lee referred to the enabling legislation, the Energy Independence and Security 

Act of 2007 (EISA 2007), which required NIST to create an interoperability 

framework for the smart grid. The EISA 2007 said that when NIST developed 

“sufficient consensus,” the Federal Energy Regulatory Commission (FERC) 

would post standards and invite comment. 

According to EISA 2007, FERC could then “adopt” standards without 

enforcing compliance with them. So, much hinged on what “adopt” meant, 

according to Lee. 

In a Jan. 31 meeting with panelists from utilities and the private sector, FERC 

Chairman Jon Wellinghoff explored whether there existed “sufficient consensus” 

around standards identified by NIST. The answer: “No.” 

“This left everyone up in the air,” Lee told me. 

Subsequently, FERC sought two rounds of comments on the issue (on April 8 

and 22) in order to resolve the issue, but Lee acknowledged that this state of affairs 

has left state public utility commissions pondering how to move forward. 

Non-prescriptive strategy important 

This anecdote merely underscored Lee’s argument that a non-prescriptive 

approach to cyber security is an important strategy. The NISTIR 7628 is 

guidance that requires heavy lifting by every utility to protect critical assets. 

Guidance allows flexibility and innovation, while mandates tend to be inflexible. 

A one-size-fits-all approach cannot account for the variation among individual 

utilities’ legacy systems and unique risk profiles. 

It’s difficult to deploy tools while utilities watch as standards are developed 

and vendors race to provide solutions, Lee acknowledged. 

“This is another area where the IT, telecom and electric sector communities 

need to come together to figure out how to use these standards in the electric 

sector,” she said. “There are some 

real restrictions in the electric sector 

that you don’t have in IT. The electric 

sector has remote devices, limited 

bandwidth and processing constraints. 

When you consider IT/telecom- 

based solutions, you have to think 

about that. 

Looking end-to-end 

“To correctly address cyber security, 

one needs to look at it end-to-end,” 

Lee continued. “It requires examining 

the technical, physical, and administrative 

procedures. Even if FERC had 

adopted a specific family of standards, 

that would not have been the entire 

solution. Those would be standards 

designed to be applied in very specific 

ways. One needs to look at the entire 

range of security that’s needed. One 

may have a good technical solution; 

however if a person is allowed to enter 

your building and log onto your system, 

you don’t have good security.” 

In Lee’s view, it is most effective for 

each utility to designate a cyber security 

leader, who may have to educate 

upward to develop executive support 

for protecting critical assets. 

“Part of the problem in approaching 

cyber security is that many organizations 

don’t have people who understand 

this,” Lee said. “Utilities don’t 

always know the questions to ask when 

vendors and integrators get involved. 

It helps to have a person dedicated to 

this task, and clearly this is not something 

one learns overnight.” 

One argument that’s both substantive 

and convincing is that cyber 

security addresses business-continuity 

vulnerability, which is a reliability and 

productivity issue. 

“Reliability is No. 1,” Lee said. 

“And cyber security supports reliability. 

I like to tell people ‘We think 

we’re at the top of the totem pole, but 

we’re not.’ We need to support cyber 

security. Typically, when organizations 

do a generic risk assessment, cyber 

security is one component, not the

only component. Utilities need to look at the business case, the cost, and make 

business-based decisions.” 

“The point that I emphasize about a risk management framework is that 

business continuity is a form of risk management,” Lee concluded. “You have to 

make decisions on where to spend resources. What’s most critical to maintain 

the operation of the business?” 

In the initial column of the series (above), Lee pointed out that effective 

security includes components such as physical security, personnel and administratative 

security, operations security, communications security and computer 

security. She also pointed out the efficacy of thinking in terms of systemwide, 

end-to-end measures. 

“When we interconnect these systems, if there’s an entry point that’s not 

protected, that’s a great way to access a critical system,” Lee told me. 

“That means that we need to look at the security of all systems,” she said. 

“That doesn’t mean you spend millions and millions. The priorities should 

be set based on an impact level. I like NIST’s low-moderate-high approach to 

impact assessment where one can take a qualitative approach. In contrast, using 

a quantitative approach, I’ve observed people argue whether we’re at 6.1 or 6.2, 

and I don’t understand the difference between 6 and 7, let alone 6.1 and 6.2.” 

Taking the steps 

But, you may be asking, how does one begin taking actual steps? 

Don’t reinvent the wheel, Lee suggested. 

“Begin with your existing risk management framework and an overall security 

strategy,” she said. “Take that as the starting point and begin tailoring that for 

control systems. Does your risk management framework make sense? Does your 

security strategy make sense? Then put together a risk assessment. Inventory 

your assets. Weigh the risk of a compromise of confidentiality, integrity and 

availability. Determine which of those that need to be addressed first.” 

Applying requirements 

Once a utility has determined its high-priority risks, it can review and apply the 

“requirements” in the NISTIR 7628, “Guidelines for Smart Grid Cyber Security.” 

“Requirements” offer guidance to effectively address certain vulnerabilities 

on a systemwide basis, Lee explained. The individual utility assesses its risks and 

prioritizes them. To mitigate those risks, the utility selects the applicable requirements 

from the NISTIR 7628 and tailors them to the specific system, in order to 

effectively address the risk. 

“When examining the ‘requirements,’ 

assess the ‘requirements’ for a 

system,” Lee said. “That’s important, 

because risk from a system perspective 

may have certain requirements 

that need to be implemented in some 

components and not in others. If one 

implements every requirement in 

every component in a system, it won’t 

function, performance will drop. For 

instance, if a firewall is required, it is 

typically installed at the boundary, not 

between every single device. Intrusion 

detection is also typically installed at 

the boundary, which is why risk must 

be assessed from a system perspective.” 

Returning to the theme that 

required standards may be inflex- 

ible and, therefore, less effective 

than guidelines, Lee said: 

“Standardization is important to 

ensure interoperability. But each utility 

must decide how it’s going to address 

cyber security. In part, the approach 

depends on a utility’s system architecture, 

the types of protocols that are 

being used, and the communications 

medium they use. The answers are specific 

to the technologies you’re using.” 

Dealing with privacy 

Finally, Lee touched on the privacy 

issue regarding customer data. 

“Utilities have had to deal with privacy 

for decades,” she said. “They have 

customer information. The difference, 

moving forward with smart meters, is 

the granularity and frequency of the 

information being collected. What will 

utilities do with that data? Third-party 

organizations want to get involved, 

particularly from an energy management 

perspective. How is information 

shared with those vendors? Who will 

be responsible for the integrity of 

that information? 

“Most states have privacy-breach 

laws. How are those addressed by a 

utility? Ownership of energy use data 

depends on the state. It is a vexing 

issue that at some point will have to be 

dealt with,” Lee concluded. 


OUT THE DOOR 


46 

The advanced 

smart grid 

+ + Viewing the trends 

By Andres Carvallo and John Cooper 

JUNE MARKED THE RELEASE OF THE ADVANCED SMART GRID: 

Edge Power Driving Sustainability, a new book by Andres Carvallo 

and John Cooper. The following excerpt comes from Chapter 6, “Today’s 

Smart Grid.” 

State smart grid dockets 

The year 2010 saw progress on many state fronts in implementing smart grid 

plans of electric utilities. In many cases, the utilities and regulators worked well 

together to launch projects without major issues. In others, regulators saw themselves 

repeatedly put in the position of reacting to unintended, negative impacts 

of smart grid implementations. Viewed together as a trend line, these separate 

cases help us draw some conclusions. 

Oklahoma and OGE 

Oklahoma Gas & Electric (OGE), the recipient of $130 million in DOE FOA 58 

smart grid investment grants, successfully maneuvered the 

regulatory process from June to August 2010 and received 

approval for its Positive Energy Smart Grid program. The 

OCC preapproved up to $366.4 million in program costs 

for the system, with the principal focus on smart meters. 

From June to August 2010, the OCC approval for a large 

smart grid project shone as a bright light in comparison to the other cases 

documented in this section. 

California and PG&E 

In September 2009, California utility giant Pacific Gas and Electric Company 

(PG&E) faced a challenge to its multibillion-dollar AMI deployment, at the 

time one of the largest and most ambitious rollouts of the 

new technology in the world, kicking off a trend of consumer 

backlash to smart grid that has only grown as the year 

progressed. As if to prove the adage that pioneers are the ones 

who get arrows in their backs, PG&E was sued by consumers 

in the San Joaquin Valley over abnormally high electric bills 

that they attributed to their new smart meters. 

As many insiders suspected all along, the results of an official inquiry revealed 

in September 2010 that the meters worked perfectly all along, but PG&E had 

dropped the ball in helping its customers understand the changes underway. 

CPUC Commissioner Nancy Ryan put it succinctly, “Better communication and 

customer service will help ensure that consumers see smart meters as something 

that is done for them, not to them.” 

Texas and Oncor 

Similarly, Texas utility Oncor came 

under fire for its AMI rollout a few 

months after PG&E did. 

With the benefit of going 

second, Texas regulators 

reacted much quicker than 

their California colleagues, 

hiring Navigant to investigate 

to identify root causes. 

Investigation results in July 2010 

likewise found the technical performance 

of the meters impeccable, but 

those consumers had high bills 

because of an unusually cold winter 

and that communication and education 

could have helped consumers 

better understand the changes, underscoring 

the lessons of the California 

case—consumer awareness will be 

critical to the success of the smart grid. 

Public opinion on both of these cases 

appears likely to influence the longterm 

future of smart grid initiatives 

and, as the following cases show, the 

funding for such initiatives as well. 

Hawaii and HECO 

In Hawaii, there was yet another challenge 

to smart grid in June 2010, but 

this time it did not concern a consumer 

issue per se. The Hawaii 

Solar Energy Association 

(HSEA) challenged plans 

for the pilot, claiming that 

Hawaii Electric Company 

(HECO) was “putting the 

cart before the horse,” since the pilot’s 

principal goal was to ratify technology 

decisions around a smart metering 

system, but it used a network approach 

that HSEA claimed would be 

incapable of supporting future longterm 

utility needs to integrate applications 

beyond smart metering, notably, 

solar PV systems and other forms of 

renewable energy. 

When it comes to renewable energy 

integration, Hawaii is a bellweather 

state—nearly 90 percent of its electricity 

is powered by imported oil, their 

electricity rates are the highest in the

United States by a large margin, and 

Hawaii also leads the nation with 

an ambitious 70 percent renewable 

energy goal by 2030. The grid 

will need a major overhaul 

to accommodate a shift to 

30 percent renewable energy, 

much less 70 percent. For 

now, the pilot is back on 

track, but Hawaii remains a 

state to watch as it upgrades 

its grid. 

“ 

Maryland and BG&E 

Maryland is the “M” of PJM, 

one of the most 

congested grids 

in the nation. 

Baltimore Gas 

& Electric (BG&E), the 

fortunate recipient of 

$200 million in federal largesse from 

a DOE ARRA grant, required matching funds to complete the contract and 

launch its project, for which they would need regulatory approval in a rate 

case. The trend line emerged ever more clearly in June 2010, as local consumer 

advocates challenged both the costs and cost 

recovery mechanisms in the rate case, leading 

Better communication 

the commission to veto the deal and send the 

utility back to the drawing board. 

and customer service 

For a time, it looked like Maryland might 

be forced to turn its back on $200 million, but 

will help ensure that 

cooler heads prevailed and the utility found 

a way to revise its filing to win regulatory 

consumers see smart 

approval in August 2010 and allow federal 

funds to flow. 

meters as something 

Two issues became even more apparent in 

the aftermath. First, consumer groups now 

that is done for them, 

had the attention of utilities and regulators 

and would likely have a seat at the table of 

not to them. ” 

any future smart grid hearings nationwide. 

Second, state regulators would not be expected 

to blindly follow the lead of the DOE; there would be no automatic state regulatory 

approval of large smart grid rate cases, with or without federal funds to 

sweeten the pot. 

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OUT THE DOOR 


48 

Illinois and ComEd 

In a case that now resembles the proverbial Gordian knot, Illinois utility 

Comonwealth Edison learned in November 2010 that making it past consumers 

and special interest groups isn’t enough—a utility can stub 

its toe on procedure, when an Illinois appeal court ruled on a 

motion by the state attorney general to deny smart grid cost 

recovery for ComEd. It is not enough to try to reduce costs 

with innovative programs; ComEd was going to deploy over 

100,000 smart meters linked to home energy management 

systems to lower costs and give customers more control. However, it also matters 

how a utility seeks cost recovery; ComEd made the mistake of using a special 

“rider,” which carries specific restrictions, which the court deemed inappropriate 

“single-issue ratemaking.” 

The net-net of this decision will most certainly be to slow smart grid deployments 

still further and likely to shift more of the burden for installation from 

utilities to vendors, making it still more difficult for small companies to compete 

in this industry. It will be hard to challenge other utility managers for being 

highly methodical and deliberate regarding innovative approaches to industry 

reform after ComEd’s experience and public wrist-slapping. 

Colorado and Xcel Energy 

One of the earliest, most ballyhooed examples of smart grid 

innovation though has to have been the Smart Grid City pilot 

in Boulder, Colorado, where Xcel Energy promised in 2008 to 

showcase the potential of smart grid with a solution cooked up 

with a bevy of vendor partners. However, in an outcome described 

by various parties as pioneer trial and error, miscalcu- 

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suffered from excess press and challenging 

delivery conditions, running 

into multiple project cost overruns 

along the way (some attributed delays 

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granite in the Rocky Mountains). 

In November 2010, the utility 

received preliminary approval for 

$44.5 million in cost recovery for 

the project originally budgeted 

at $15.3 million (March 2008), 

$27.9 million (May 2009), and then 

$42.1 million (February 2010). At 

the time of this writing, the case was 

under review by Colorado regulators, 

but based on arguments so far, prognosticators 

expect the full recovery to 

be whittled down to a partial recovery. 

Among the ultimate lessons learned 

here for utilities may be the value of 

setting achievable expectations and 

the wisdom of gaining cost approvals 

up-front, before proceeding to break 

ground on a smart grid project. 

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FERC vs NERC: A grid control showdown over cyber security

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