Transcript: Barriers and Challenges to Building The Smart Grid

THE CNA CORPORATION
 
BARRIERS AND CHALLENGES TO BUILDING THE SMART GRID
 
WELCOME:
FRANK ANDERSON,
PRESIDENT,
DEFENSE ACQUISITION UNIVERSITY
 
MODERATOR:
MITZI WERTHEIM,
FOUNDER AND DIRECTOR,
THE ENERGY CONVERSATION
 
SPEAKER:
JON WELLINGHOFF,
COMMISSIONER,
FEDERAL ENERGY REGULATORY COMMISSION
 
 
MONDAY, SEPTEMBER 15, 2008
 
Transcript by
Federal News Service
Washington, D.C.
 
 FRANK ANDERSON:  Good evening.  Let’s try that again.  Good evening.  It’s great to
be here with you.  We have an exciting program this evening.  I have the great honor and
privilege of introducing our guest speaker this evening, Commissioner Jon Wellinghoff, who is a
member of the Federal Energy Regulatory Commission.  He’s going to speak to us this evening
on Barriers and Challenges for the Smart Grid.  
 
All of you have bios.  I’m going to share a few things that I found interesting.  I’m not
going to go through it all because I’m depending on the fact that you’re going to read the bio.  
 
He is a lawyer, has his J.D. from the Antioch School of Law.  He has a master’s degree in
mathematics from Howard University.  He has a B.S. from the University of Nevada, Reno, also
in mathematics.  So we have a lawyer who can really count – (laughter) – which is important in
this business.  
 
He is a practicing energy law specialist, has spent over 30 years in the business.  He is
currently on the Federal Energy Regulatory Commission.  He’s starting his second term.  He has
been a consumer advocate in Nevada, representing consumers before the Nevada Public Utilities
Commission.  So he has looked at the business from the perspective of consumers.  
 
He has been in the regulatory business.  He has represented clients who were working on
energy commissions.  He has written broad-ranging policies that impact this sector.  Primary in
that was his role as principal author of the Nevada Renewable Portfolio Standard Act.  I mention
that because this has led to Nevada being one of two states to receive an A-rating by the Union
of Concerned Scientists.  
 
The subject of this evening is very important because as we start to look at alternative
sources of energy, the electric grid is very, very important, as we start to look at how we reduce
our ties to the current oil-based energy medium that we have today.  
 
We thank Commissioner Wellinghoff for sharing his evening.  I am not going to take
more time.  You didn’t come to hear me; you came to hear him.  So will all of you please join me
in providing Commissioner Wellinghoff a round warm of applause?  
 
(Applause.)  
 
JON WELLINGHOFF:  Thank you for that introduction and I want to thank Mitzi for
getting me here.  She’s the one who kind of glues this group together.  So we’re really happy to
do whatever we can to try to present some information to folks that hopefully will be useful this
evening.  
 
I’m going to try to use my Lavaliere mike here and turn this other mike off – see if I can
do that.  You got it?  Okay.  Okay.  Am I on here?  You need to put the volume up on the
Lavaliere?  Can everybody – I’m not – yes, it’s on.  I got a green light.  I got a green light, but I
got nothing.  I can use this.  That’s okay.  There we go.  Okay, we’re on.  We’re live.  All right.  
 
So what I’m going to do is step down here, just talk in front of the screen, and move
around a little bit.  
 
I was asked to talk about barriers and challenges to building the smart grid, but as you’ll
see, as I go through this presentation, I don’t like that term “smart grid.”  I don’t think it’s very
descriptive.  I was up at – I was up in Boston last week with the board of directors of the New
England ISO.  How many people here know what an ISO is?  Okay, maybe about a third.  ISO is
independent system operator.  
 
They operate the grid in New England from Connecticut on up through Maine, and they
do that independently as a non-profit agency, basically under agreement with all the transmission
owners in New England that own the transmission system and with all the generation owners and
operators.  So basically, they operate that grid on a daily basis from an economic dispatch
perspective, and they also run a market, a real-time and a day-ahead energy market in that area. 
And they’re under the auspices of FERC, which created those under an order called Order 2000.  
 
But anyway, I was meeting with their board of directors and we were having some
discussions about the smart grid.  And this one member of the board of directors, a professor
from MIT, an electrical engineering professor, he said, well, what does smart grid mean?  And I
figured, well, if the electrical engineering professor from MIT needs to ask what it means, then
we all are in trouble.  
 
But, basically, the point he was trying to make was it means different things to different
people and to him – and after he got through talking about it, I fully agreed with him – to him,
the smart grid is not a thing.  It’s not an “it.”  You can’t just put the smart grid in place as an it
and then you’re done with the smart grid.  It’s a continuous process.  So that’s what I’m going to
talk about today.  I’m going to talk about today, this evening, what I’d rather term as energy
intelligence, enhancing the road to energy productivity.  
 
So when we talk about an intelligent electric grid, we have to look at it from the
standpoint of the component parts.  Of course, there’s a grid operator, whether it be an
independent system operator, which there are in certain areas of the country.  There's only six
independent system operators – or actually, there's seven – six under FERC’s control – in the
country: New England, New York, PJM – which is the Mid-Atlantic grid operator that goes all
the way from New Jersey to Chicago – Midwest ISO, which goes from Minnesota south to Iowa
and Missouri and there’s one in California.  There's actually one below the Midwest called SPP,
which is in the Oklahoma area.  Those are all under FERC.  
 
There’s another independent system operator that is in Texas called ERCOT, and they’re
not under FERC because they’re kind of an island.  Texas is like an island.  They don’t
interconnect well with other states, so they’re not under FERC jurisdiction.  
 
So you have to look at the grid operator.  You have to look at all the generation systems –
which I should have a picture of that out here – that are the central station generation systems
that connect into the interstate transmission system.  You have to look at that transmission
system as it then interconnects into the distribution system that goes into all of the local areas,
the businesses and residences that comprise the towns and cities that we live in, and those
distribution operations usually by a local distribution company, whether it be your local utility
company, but ultimately, it's going to get into your home.  It's going to have in the home or
business – lots of different end uses.  
 
They may be smart devices.  You may have a smart meter, something called a customer
portal.  You may even have, in some instances, distributed generation storage in that facility
today or in the future.  And someday, we may even have things like plug-in hybrid electric
vehicles and other distributed resources like wind, et cetera.  
 
But what can make all this smart in essence is this.  We have to have two-way flow of
information and power.  If we don’t have that sharing and integration of that information as a
system overall that can go all the way from the toaster in your house to the grid operator out at
the transmission level, then it’s not an intelligent energy system fully.  But it’s not something
we’re going to put in place overnight.  It’s something that's going to happen over a series of
steps.  
 
So if we look at this from a different perspective – let’s look at a 10-year grid outlook. 
The CEOs of the utility companies in the country were surveyed.  What do they see over the next
10 years?  Well, 20 – oops, I didn’t mean to do that.  Let’s go back.  Okay, I’m not going back
here.  Hit it again.  There we go, okay. 
 
Ten-year grid outlook – what do they see over a 10-year period?  Well, 21 percent of
them saw advanced storage on the grid and advanced storage can take a lot of different forms.  It
can be things like plug-in hybrid electric vehicles that, in fact, are a form of storage because you
have batteries, and in some cases, fairly large batteries, 10 to 20 kilowatt hours of battery storage
in a plug-in hybrid – that can be storage.  It can be larger systems of storage that actually utilities
put in the grid and actually a lot of utilities are looking at putting in storage now from kilowatt
size all the – multiple kilowatt size all the way up to megawatt size of storage.  
 
Also, 32 percent said they saw micro-grids, where you would have actually islanding of
grids in certain areas.  For example, on a military base, you may have a micro-grid that is a
system that could be self-contained ultimately, that could island from the rest of the system, that
could be self-supporting, based upon the internal generation within that micro-grid and the
systems that were there.  It could be its own system, ultimately.  
 
Sensors on most consuming devices is another thing that many people are seeing; 62
percent say they will see that in the next 10 years.  
 
Real-time pricing – 81 percent of the CEOs surveyed said that they believe within the
next 10 years, they’ll see prices that will go to consumers at a retail level based upon what the
real-time prices are.  Right now, 90 percent or more of the people in this country get a bill once a
month and the only price you see is that bill once a month.  You don’t know what you’re
consuming hour by hour or even day by day.  You only know what the bill is at the end of the
month, and you pay that bill, but you don’t have any feedback as to what happens with respect to
the consumption in your house vis-à-vis the prices.  
 
And I can tell you, the price that you see on the bill is an average price based upon
historical numbers that may be six months or more out of date.  You see an average monthly bill
that may be based upon natural gas prices that were six months ago that ultimately, will catch up
with you and catch up with your bill.  But from a standpoint of having feedback real-time to you
as to whether or not you should reduce your consumption, change your consumption patterns, or
do something that’s going to impact your bill because of the price changes that are happening in
real-time, most people don’t see that.  More people are going to see that.  
 
Plug-in hybrid electric vehicles – 83 percent believe that’s going to be something we’re
going to see in that period of time.  
 
Demand response for system end users – this is something we’re seeing right now at a
level of industrial and large commercial customers and something that we’ll see all the way
down to the consumer level.  Demand response simply means that when you have a system load
curve over a day period, where the load starts to go up over the day, and during a hot summer
afternoon, it peaks at a certain period and then later in the night, it goes down.  Doing things at
that peak period of time that can reduce that load can reduce real-time prices during that period
of time.  
 
And so we’re seeing consumers now – large consumers especially are actually bidding in
demand response to these organized wholesale markets.  They’re bidding in their willingness to
change and shift their patterns in certain ways that will save them money, or provide them with
payments, actually.  You’re seeing large aluminum factories do this; you’re seeing large
manufactures do this.  You’re even seeing, as I say, commercial establishments like Wal-Mart do
this to ultimately bid into these markets in such a way that it reduces that peak level and by doing
so, will reduce the real-time prices in the market because you don’t have to bring on expensive
peaking generation to meet the loads.  
 
So that’s not only – certainly, 84 percent say it’s going to happen.  Well, it’s happening in
many, many parts of the country today.  
 
And then internet billing and real-time data consumption is something 96 percent see that
it’s going to happen. 
 
So this is what some of the things the CEOs see as what’s going to happen as to changes
in the grid that may be part of what some people would define as a smart grid.  
 
So if we go down the list of items that we might look at as energy intelligence, the
current grid is largely electromechanical.  The future grid will be digital.  Right now, we have
one-way communication, if any.  In many instances, there’s no communication from the
consumer level to the grid operator or even to their local distribution utility, but we will have
two-way communication.  Now it’s built for central generational.  We have a model where we
have large central stations and transmission lines to deliver the power down to the distribution
level to the customers.  
 
We’ll have ultimately a grid that accommodates distributed resources; meaning
accommodates not only central station resources, but also things like distributed generation,
photo-voltaics, combined heat and power, cogeneration, and also energy efficiency, demand
response and conservation.  All those things are distributed resources.  
 
Right now, we have this radial topology.  Ultimately, you’ll have a network topology.
 
There’s very few sensors on the grid today.  Monitors and sensors will be throughout the
grid in an intelligent system. Right now, it’s basically blind.  Ultimately, it’ll be self-monitoring. 
Now, we have to have manual restoration.  Most of the time – the only way Pepco knows that
there’s outage in my neighborhood is somebody calls up Pepco and says, hey, our power’s out;
when are you going to fix it?  But what we’ll have ultimately is sensors on the system that will,
in fact, not only provide immediate feedback to your local distribution utility and to the
transmission operators as to what’s happening, but it’ll be self-automated restoration in many
ways with alternative switching and rerouting that will be done via computer.  
 
Right now, it’s prone to failures and blackouts.  Ultimately, it will be adaptive, protective
and islanding.  Checking equipment happens manually now.  Equipment will be monitored
remotely.  Emergency decisions are rarely made by committee or by phone, as I indicated. 
Ultimately, in the future, decision support systems will be predictive and reliable.  
 
Limited control over power flows – there’ll be pervasive control over power flows. 
Ultimately, you’ll have as much control from a system operator and from a local distribution
entity where they will actually be able to go down local distribution transformers and adjust
voltages to take account of the differences in loads during the day and during the seasons of the
year to optimize the operation of the system.  
 
Right now, there’s limited price information, as I indicated.  There’ll be full price
information to consumers to be able to use to modify and control their loads – and few customer
choices.  Ultimately, there’ll be many customer choices.  And hopefully, to make all this work,
we’re going to have to automate those customer choices because very few customers are going to
want to sit at their computer all day figuring out how long they need to leave their toaster on so
they can adjust for prices that may happen today or tomorrow or whatever.  
 
So these things are actually going to be built into appliances.  In fact, I got a whole group
of slides today from Whirlpool, that I didn’t have time to put on this presentation, of some very
advanced things that they’re doing with dryers and with washing machines and with water
heaters and a whole range of appliances that they make that will make them more grid
responsive.  I’ll talk a little bit about that, but I’m sorry I don’t have those slides because they’re
really quite interesting.  
 
So when we talk about energy intelligence – and from my perspective, I talk about it
from five different views.  One is intelligent load control.  When I talk about load control, that’s
loads on your side of the meter.  That’s your toaster; that’s your television; that’s the lights in
this room.  That’s anything that a customer uses.  We’re going to have intelligent load control, so
how much sense does it make for you to have the defrost cycle on your refrigerator operating
during the utilities peak?  Well, it makes no sense whatsoever.  
 
But if we had – but right now, you don’t know when the defrost cycle’s on and every
refrigerator has a 500-watt heater, in essence, to defrost that section of the refrigerator that comes
on and off as it’s ultimately needed.  Well, if you could control it in a way that ensured that no
one had their defrost cycle on during the utilities peak, just think how much we can lower that
peak ultimately.  That would be intelligent load control.  
 
Intelligent metering infrastructure is that interface between you and the utility to get that
two-way communication going back and forth.  
 
Intelligent distribution operations is the distribution system, intelligent transmission
operations.  And ultimately, intelligent asset management is the management of all the assets in
the total package.  These are the five components, as I see, of a smart or intelligent electric
system.  
 
And so what characteristics will that system have?  Well, one, it’ll be self-healing, as I
indicated.  It rapidly detects and analyzes, reports, and restores outages.  It’ll empower and
incorporate the consumer, and I think this is the most important part.  Right now, you get that bill
once a month.  That’s about it.  That’s your whole relationship with your utility company.  You
have no empowerment as to how to control that bill.  
 
That bill basically is what you get and you can certainly put in compact fluorescent light
bulbs.  You can do certain things to change your usage here and there, but, ultimately, you don’t
get any immediate feedback and you don’t have a multiple of ways to ultimately control that
usage.  That ability to control that usage is going to expand tremendously by empowering and
incorporating the consumer with that two-way communication.  
 
It’s going to be tolerant of attacks, mitigates, and is resilient to physical and cyber attacks
and we have a huge, huge problem in this country with respect to the potential of cyber attacks
on the grid.  In fact, there’s a bill currently pending – they’re working on putting a bill together
in Congress right now to give my agency, FERC, additional authority to, in essence, go in and
request – order utilities to correct certain situations with respect to pending potential cyber
attacks.  And, again, we need to set up a grid in such a way that we can minimize the ability of
those attacks because they could have devastating effects on the grid.   
 
Provide necessary power to provide that in a quality sense – in other words, the exact
type of power you need, the exact level of power you need for the end uses that you’re using and
it’s got to be consistent with consumer and industry needs.  It has to accommodate a wide variety
of supply and demand.  It can’t be just accommodating those central stations that we have now. 
It has to accommodate all the things that are going to happen on the consumer side that will, in
fact, allow those consumers to reduce their overall total bills.  
 
And it has to fully enable the churning electricity markets and here, I believe, is one of
the most important aspects of this intelligent energy system.  To the extent that we can have
energy markets that increase the ability of other players to come into the market, aggregators
who can come in and help customers do demand response and bid that demand response up into
wholesale energy markets, that’s being done today.  There’s – I can name five or six aggregators
nationwide who now come into businesses and industrial facilities and actually take those
customers, aggregate their demand response reductions, and bid that into those wholesale
markets in ways that lower peak and lower costs for all consumers in those markets.  This
aggregation ability, and the ability to accommodate those different players outside of the utilities
in these competitive markets, is going to assist everybody.  
 
To the point we have plug-in hybrid electric vehicles, we’re going to have aggregators
who will come in and assist those owners of those plug-in hybrid electric vehicles to use those
vehicles as grid support devices when you’re not driving your car.  When that’s plugged into the
grid, there’s ways to use that plug-in hybrid for things like regulation services that will not
disrupt you from charging the car in any way, but will allow you to actually get payments from
the grid for using it to support the grid for regulation services.  And this is already being tested
by people up at the University of Delaware in conjunction with PJM and we’ve been working on
this at FERC.  
 
So let’s look at that first level, at intelligent load control and intelligent metering
infrastructure.  In the consumers’ side of things, you're going to have, again, individual devices
who will be communicating with each other and communicating out to the grid in such a way
that, as I mentioned, you won’t have your refrigerator defrost cycle on during the peak time
when the real-time prices are 20 cents a kilowatt hour.  Why not wait until the evening when the
prices are down to eight cents a kilowatt-hour?  It makes more sense.  And there may be no
reason, for example, to have your air conditioner operating at the same time your refrigerator
compressor’s operating, if you could lower your peak in your overall house and reduce peak
energy charges on your bill by having diversity of load.  
 
All these things will be done with internal communications between devices and with
some type of online energy management system that ultimately, could be installed in the facility.  
 
So these are the type of things that you can see happening with intelligent load control
and intelligent metering of infrastructure, and it may – ultimately, having a physical meter like
you have in your house now, or you may not even have a meter.  It may be a virtual meter
ultimately up through the internet where you would aggregate all your loads on that internet site. 
And it would be used for billing by your utility and used by you to control and determine how
these loads were operating, and you could set parameters that would automatically operate
without your further intervention, so you wouldn’t have to be bothered by it.  
 
If we look at using intelligent load control, here’s one example.  This was an experiment
done by Pacific Northwest National Labs on the Pacific Peninsula up in Washington, on the
Olympic Peninsula.  What they did is they went into 150 different homes with IBM and a
number of appliance manufacturers.  They installed a chip in water heaters, in dishwashers,
washing machines or refrigerators.
 
And that chip could actually sense frequency response on the grid.  It could determine the
variations in frequency and those variations in frequency predicted what were the variations in
load and so, based upon that, they could correlate it with what the prices were on the grid.  And
based upon that correlation, they could determine from that when these appliances should be on
or off and this was all done automatically.  So, ultimately, these appliances could determine
whether or not they would be on or off at certain times.  Consumer could have an override,
certainly, if they needed to use them for a certain time, or if they couldn’t have them interrupted. 
The consumer had full control.  There was no problem there.  
 
Unanimous support by the consumers who were in this test pilot – they saved on average
– I think it was about $30 or $40 a month on their electric bill.  Actually, they got a credit back
on their bill for their contribution to the program and the interesting thing was this contribution
wasn’t a subsidy being paid to them.  It was actually based upon the value that their participation
in the program was providing to the grid.  So this is a real value that’s – that, in fact, helps
consumers participate with their own loads in the grid overall, and at the same time, helps the
grid and helps other consumers by lowering total costs.  
 
So what makes a meter smart if we look at intelligent meter infrastructure?  Well, it has
to have interval measurements, both consumption and time.  It has to have an interface with data
monitoring and it has to monitor also discrete loads in your house.  It has to have automatic
transmission of resulting data and that data has to go to the energy provider, which would be the
one who’s going to bill you, ultimately, for the energy that you’re taking.  It’s got to go to the
consumer as well, so the consumer has the ability to see what’s happening with their loads.  And
it should go to the grid operator, so that grid operator can do these optimizations of the total grid.  
 
We have to think of these things as a total system.  We can no longer think of behind-the-
meter loads, distribution system, transmission system, central generators as separate discrete
parts.  We have to think of this as a total system if we’re going to optimize the system, if we’re
going to reduce costs, and we’re going to enhance energy productivity and energy efficiency, and
of course, two-way communications with data collection and monitoring and ancillary services
and load control capabilities.  
 
There’s only about less than 3 percent of the 135 million meters in the country that have
this capability today and it’s an investment that’s, as you can see here, starting to take place. 
Projects are being undertaken by utilities to put these meters in.  The average length of putting
them in is 5.7 years.  The number of total meters, 2.6 million and the number of electric meters is
2.2 million.  The total is higher because a lot of these are – some of these are gas meters as well. 
The average length of the pilots are nine months.  These are going in all over the country and
costs are relatively high.  
 
Con Edison's got a project that’s over $890 million.  Baltimore Gas and Electric, near
here, is doing a project that will be over $400 million and you can see Center Point’s got one
that’s $1.8 billion.  That’s in the Houston, Texas, area, I believe – and PG&E, $1.7 billion,
Southern California Edison, $1.3 billion.  
 
So these are not inexpensive projects, but ultimately, there are cost benefits here and the
benefits ultimately are to the consumer.  Ultimately, it’s going to pay back the consumer more
than it’s going to cost over time to put this type of infrastructure together.  
 
The number of installations, as I mentioned to you – there’s only about 5 percent of these
right now are what you’d call intelligent meter infrastructure.  There’s 19 percent, which is
called AMR, which is automatic meter rating, but it’s one-way data, basically, one-way data
going from the consumer to the utility, so they can drive by, in essence, or at their central station
get the data off the meter to read it.  Beyond that, it provides little, if any, other data.  And that
19 percent will have to be replaced with this intelligent meter infrastructure.  Seventy-six percent
have none of this intelligence at all and there’s about 135 million meters out there.  
 
So, let’s look at now the distribution level, at distribution substations, transformers and
distribution lines.  We’re going to need increased information with granularity of the controls, as
I mentioned, all the way down to the distribution transformer where the voltage taps in those
transformers can be set remotely by the utility based upon the loads in the local area.  If there’s
overloads or if there’s transformers going out and they need to bypass a transformer, all that can
be done automatically with this kind of control.  
 
So you have distributed intelligence with a network system that has advanced outage
management capability and enables effective integration of demand response, so that consumers
can utilize demand response back up into the system.  That’s got to be integrated with GIS
systems as well.  
 
So beyond the – and here’s an example of a pole transformer with again, the ability to
have dynamic voltage regulation, where that voltage could be regulated based upon the loads in
this local neighborhood area to ensure that the amount of line losses are minimized.  We can
minimize the line losses.  It’s going to minimize the costs for consumers in that particular area. 
And in doing this throughout our whole distribution system, we’ll minimize the total distribution
costs, which you probably see as a separate line item on your bill.  
 
Let’s look up at the transmission level, where you have major transmission systems that
go out to the central station plants and provide link lines between large distribution centers with
transmission level voltage usually above 69kV or above and we have some lines in this country
as high as 765 kV.  We're going to have advanced data collection there, advanced operation and
control, substation automation at the transmission level, and dynamic loading capabilities. 
 
Dynamic loading capabilities, what I mean there is, these lines when they get loaded,
they sag ultimately because they get hot, and so they have loading restrictions that are based
upon parameters that have been set by engineering calculations.  Those loading parameters may
not reflect the actual in-situation field conditions.  There are now devices that can actually
calculate that sag precisely and give you dynamic loading control.  So you can load lines
precisely based upon temperature, wind conditions, and all these other variables based upon
actual the siting of those lines and determining how much they’re sagging.  Then you know how
much to load them and how much they can take over a period of time based upon actual
conditions, and save tremendous amounts of money for consumers.  
 
Nonlinear modeling and simulation – another very important area.  Right now, we
operate the grid based upon models that we – predictive models that we put in place using
basically an algorithm that replicates the AC system using a DC proxy because it’s a linear
system under a DC proxy, but that’s not actually how the system operates.  Our system is
primarily AC.  So if we can actually do nonlinear modeling using nonlinear functions that will
give us the actual system operation parameters in a way that we can get from our model better
data as to how that particular system will operate given the conditions, we can save, again,
tremendous amounts of money.  
 
And advanced visualization tools are another important thing for the grid to be able to
visualize how it’s operating and respond quickly to those visualization systems.  
 
Let me give you an example here of a transmission system – things that could be done to
improve the situation on operation, and by doing so, save tremendous amounts of money.  The
2003 August blackout that hit the Northeast, if prior of that blackout, there were something on
the transmission system installed called a phase-monitoring unit, which would have been
installed in multiple locations, which they’re now starting to install, it could have, in fact, shown
the operators the out-of-phase situation at the time.  We could have, in fact, predicted that
blackout was about to happen and could have taken advance steps to stop it, but the reason we
couldn’t is because the current scattered data that we get from the transmission system gives data
every three seconds.  A phase monitoring unit will give data every 30th of a second.  
 
That order of magnitude increase in data, in timing, will allow the operator to predict
quickly enough the ability of the system outage, which, in essence, took a period of
approximately nine seconds ultimately for it to go from Ohio to New York.  In that nine seconds,
if you’re getting data every 30th of a second, you’ve gotten a lot more data than if you’re getting
it every three seconds.  It would give that operator enough time to be able to push the button, or
more precisely, if we would have had predictive modeling in a nonlinear sense, allowed the
computer to have taken certain actions that could have potentially avoided this entire blackout
that happened that cost billions of dollars for this country.  
 
So it’s this kind of operational predictive sensing and then response to that sensing
through proper modeling and operations that can have a significant effect on reducing costs and
improving efficiency over all the system.  
 
Asset monitorization, again, will improve the utilization of the whole T&D system, and
effectively manages the assets from a lifecycle perspective.  
 
MITZI WERTHEIM:  What is T&D?  
 
MR. WELLINGHOFF:  Transmission and distribution system.  So it looks at not just one
portion of it, but looks at all the assets collectively and helps you manage that in a way that
improves effectiveness of the asset management systems to ensure that if things are starting to
degrade, you start managing those systems from a lifecycle standpoint that can reduce costs
overall and ensure that you’re putting in things that lifecycle-wise ultimately pay off.  
 
One of the intelligent asset management tools is a visualization system, looking at some
standard metrics like balance of resource and demand, and also frequency response, or you can
have real-time alarming, which would go back to what I talked about with the phase-monitoring
unit that ultimately, would give you some alarms immediately when you saw things going out of
phase, and have area-wide situational analysis that could show you predictively ahead of time
where this out-of-phase frequency was going, to tell you then how to stop it with the situational
awareness, ultimately.  
 
So these are the types of tools that grid operators are now starting to incorporate into their
grid systems to utilize to ensure that these types of situations can be avoided, and we can operate
the system on a day-to-day basis more cost effectively, reducing losses and improving efficiency
overall.  
 
So where does FERC come into all of this?  This is the end of this – about the end of
where I’m at now.  I think I’ve got a couple of more slides.  
 
FERC looks at a number of things.  Our authority, under the Federal Power Act, is to
ensure, number one, that rates are just and reasonable, and the rates that we oversee are those
charged for the operation and utilization of the interstate transmission system.  We have
authority over the interstate transmission system.  So any rates that are charged in that system are
rates that FERC has ultimately approved.  
 
We also have separate authority under the 2005 Energy Policy Act under Section 1223, to
encourage the use of what’s called advanced transmission technologies.  And those advanced
transmission technologies are listed in that act and many of the things that I’ve already talked
about, like phase-monitoring units and these other sensors and other devices that ultimately can
make this grid more efficient and more effective.  So FERC is given affirmative responsibility by
Congress to promote these.  
 
We also have responsibility under Section 1221 of the act, which is Section 215 of the
Federal Power Act, which requires FERC to be responsible for the overall reliability of the bulk
power system, which includes the interstate transmission system and attendant aspects of it, like
distribution systems and generators as well.  And so ensuring that this reliability is, in fact,
maintained requires that we look at things like intelligent energy systems that can improve
reliability.  
 
Then under the 2007 Energy Act, we have certain smart grid provisions, which I’ll talk
about here, I think, in a second, but let me talk a little bit about FERC’s action on wholesale
market platforms for demand-resources, which do require some level of energy intelligence. 
And these markets that I've talked about, the New England ISO, in New York, PJM, MISO,
which is Midwest ISO, California ISO, and Southwest Power System, all these markets
ultimately which are usually either real-time and/or day-ahead energy markets have some form
of demand-resource participation.  
 
In other words, demand response, or in some cases, for example, with New England and
New York and PJM, actually capacity, like energy efficiency, can bid into these markets.  So
these are part of the tariffs that FERC has approved for these markets to ensure that customers at
any level, whether it be an industrial or commercial customer, or it could be all the way down to
a residential level – usually through aggregators because there usually are limits like one to five
megawatt limits to bid into these markets, but usually they can be aggregated from smaller loads
– can bid into these markets and actually receive payments from those markets for lowering
demand in those markets, providing ancillary services in the market.  
 
In fact, New England ISO, New York and PJM all have ancillary services markets right
now, where demand response can bid into that.  MISO and the Cal ISO are developing those
markets.  So you could, as I mentioned before, have your plug-in hybrid electric vehicle that
could provide regulation services into New England, New York or PJM.  And if it was at the
proper level, aggregated, and had the right communication controls to be able to participate in
that market, you could actually receive payments for participating in that market anywhere from
$500 to $2,000 per year per vehicle, depending upon how long and how often you participated in
that market, which could be a substantial amount to offset the cost of that new vehicle.  
 
Let me give you an idea of demand response, how it’s contributed in these markets.  For
example, in our area here, in PJM, in the summer of 2006, there was 2,050 megawatts of demand
response that actually bid into the market during peak times to reduce peak, which was 1.4
percent of the peak.  In 2007, there was 3,733 megawatts.  So ultimately, you can see that this
demand response participation is substantial and has been growing – growing significantly.  It’s
up to 2.8 percent of the peak at NYISO in New York and actually, 4.1 percent of the peak in the
Cal ISO.  
 
So it can be a substantial portion of the peak load requirements or peak load resources
ultimately, reducing requirements of other more expansive oil and natural gas generation that
otherwise would be fired up to meet that peak and is put in there to reduce it overall.  
 
One specific example is the PJM demand response that can be seen over time here,
starting in 2002 and this is cumulative load in megawatt hours here.  We have less than 10,000
megawatt hours in 2002 and as of January 31st, 2007, there were over 270,000 megawatt hours of
demand response bid into PJM.  So you can see the substantial growth in demand response.  
 
And the effect of that demand response ultimately, as far as benefits on the grid can be
seen, I think, very graphically here, where we had one week period of time in PJM in the end of
July, first part of August, in 2006.  And if you look at the red lines here, the red lines represent
what the actual peak would have been if demand response was not called by PJM.  
 
That is a back cast because they actually did call demand response starting on this first
day, and even though the temperatures went up significantly from what it would have been, the
actual demand requirements were significantly lower and it gave you a lower – they're called
LMP – locational marginal price – in PJM.  And you can see from this second day on to the third
and fourth day, the difference was substantial between what actually was the locational marginal
price and what the predicted price would have been if no demand response would have shown up
and would have been available.  
 
The ultimate result was this one week, in and of itself, with demand response, when you
back cast the prices without it, was a $650 million savings to consumers from that demand
response.  And the calculation of the costs of that demand response to the consumer during that
week was about $10 million.  So there was a net of about $640 million the consumer saved in
that one week by putting that demand response into that market. 
 
So FERC is also looking at regional transmission planning and in that regional
transmission planning process, which we have authority over under our liability requirements,
and under Order 890, we have, in fact, directed all transmission owners who must conduct this
planning to use and consider comparable to central generation demand response, energy
efficiency, and all these other distributed resources, including upgrades to the grid system.  Part
of their planning process, they have to incorporate that into the interstate transmission system
that this regional transmission planning has to be done over.  
 
Then I talked about the 2007 act.  Let me tell you a little bit about it.  The policy in that
act supports the modernization of the nation’s electric transmission distribution system.  It stops
short, however, of defining a smart grid, but it does require DOE to establish a smart grid
taskforce with representatives from federal agencies, including the FERC.  It requires DOE to
establish a smart grid advisory committee with private and non-federal public sector stakeholders
in that committee as well.  So FERC is participating in this effort with DOE and is part of this
grid process.  
 
This section of the act also authorizes, independent of the Federal Power Act, FERC to
issue a rule making to adopt smart grid standards, and again, interesting, it doesn’t define smart
grid, but it asks us to adopt these standards.  The standards are actually being developed by the
National Institute of Standards.  On a consensus basis, those standards will be brought to us. 
FERC, though, will actually be the agency to adopt those standards.  There’s no explicit
limitation on FERC’s authority to adopt the rule and the standards could apply to local
distribution, as well as transmission facilities.  
 
Interesting part, though, is the standards – there’s no mandatory aspect to the standards,
nor is there any enforcement.  So I’m not sure exactly what Congress had in mind here, other
than they were interested in certainly moving forward with adopting some standards to put in
place this overall system of energy intelligence, but exactly how that’s going to be enforced and
how we will roll it out, is going to be interesting.  
 
We’re going through the process.  We have representatives with the National Institute. 
We have representatives attending these meetings with the National Institute of Standards. 
They’re developing the standards on a consensus basis that will come to us to be issued in the
FERC rule, but beyond that, it will be interesting to see how these standards ultimately then are
taken up by the nation’s utilities, given, as I say, there is no explicit enforcement authority in the
act.  
 
So let’s look at what’s all the costs and benefits of this?  Well, if you look at some of the
things that I’ve talked about of energy intelligence, on the residential level, commercial level,
and network infrastructure, total costs we’re talking about 45 to $60 billion.  It’s not a small
price tag at all.  But if you add up the benefits to homes, to ability to do this demand response,
and all the benefits I talked about there, the investment in intelligent grid technologies and what
that can do, is to overall lower cost for everybody in the grid, and interactive storage
technologies and micro-grids, how that can ultimately, through distributed generation and other
installations, save money on the grid.  
 
The total yearly savings are predicted to be from 14 to $21 million.  So you’re looking at
a three-year payback ultimately for this type of an investment – something that will pay back
over and over to this country by putting this kind of infrastructure in place.  
 
Barriers and challenges – and this is really what I was asked to talk about.  It took a little
while to get here, but ultimately, here you have a map of the independent system operators and
all these colored areas are where the independent system operators are located.  All the white
areas are areas of the country that have no independent system operators.  The transmission
systems in those white areas are operated by the local utility companies or the utility companies
who own the transmission in those areas.  
 
In the Southwest – excuse me – Southeast it's largely Southern Company, Entergy and
Florida Power and Light are the three big owners in the southeast area.  In the western United
States, there’s a whole array of utilities.  Pacific Corp. has a large chunk of the West and
Northwest.  In Nevada, there is one utility that owns the utility system throughout the State of
Nevada.  Arizona, there’s a number of different utilities.  APS and Salt River Project are two
large ones.  So it varies throughout the West.  But ultimately, these are not in places where
there’s these organized wholesale markets, nor are there independent system operators.  
 
So the first barrier, as I see it, is this cost-benefit business case.  The business case has to
be made to consumers that this system, an investment of $60 billion out of their pockets, makes
some sense to them, that there’s going to be a return.  But if it’s a three-year payback, that’s a
30-percent return on your money.  I don’t know where you can invest your money today and get
a 30-percent return – very few places that you can do that.  So that’s one of the biggest things, is
that business case has to be made ultimately to the consumers.  
 
Secondly, consumer information and awareness of the benefits – consumers have to
understand what this is going to mean to them.  And I think there’s a lot of consumers who are
very concerned that, gee, put this smart grid in place and all it’s going to mean is I have to decide
when my washer comes on versus my toaster versus when I use my air conditioner.  I don’t want
to do that.  That’s just not – and most consumers don’t want to do that.  
 
So, ultimately, the system has to be transparent to consumers, and we have to be able to
understand how that can be done in a way that consumers can benefit from it, but yet not have
those intrusions into their everyday lives because their job is not controlling the loads in their
house.  They have a real day job.  Most consumers do.  
 
Also, flow-through of benefits to consumers – we’ve got to make sure that these benefits,
as in fact, they are seen at the wholesale market transmission level, as they’re seen at the
distribution level, they have to be flowed through to the consumers because consumers often
times are asked to participate in some of these programs, but their local utility may decide, well,
gee, I’m only going to give the consumer this piece here and we’re going to keep this other piece
here.  
 
So ultimately, there have to be ways for consumers to participate in these wholesale
markets through aggregators, or through other ways.  And that’s why I talked about these
competitive markets that are very important to have competitive players in these markets, so
consumers can have choices as to how they can participate.  They can participate in ways they
can maximize their benefits to them. 
 
And then conflicting jurisdictions – we have the issue of the federal jurisdiction and the
state jurisdiction, and I’m trying to work as collaboratively as I can with my fellow regulatory
commissioners in the states.  In fact, we formed a collaborative effort called the NARUC-FERC
Demand-Response Collaborative.  NARUC is the National Association of Regulatory Utility
Commissioners, which is made up of all the state commissioners.  We meet three times a year at
the NARUC committee meetings.  
 
We put a study together to look at the barriers between federal and state jurisdiction to
get these things in place, but there’s a lot of reluctance on the side of state regulators and their
reluctance is very simple.  They don’t want to start – they don’t want to be put in a position to
have to put in place a rate increase for their consumers without being able to demonstrate
benefits, demonstrable benefits, for that rate increase because a lot of those consumers have
suffered very high rate increases for other reasons in the past, primarily because of fuel price
increases for natural gas and for infrastructure costs for new plant construction, et cetera.  
 
So I can understand the concern of state regulators.  We have to figure out how we can
communicate the benefits to consumers and help state regulators overcome these barriers, so we
can put these systems ultimately in place and overcome these conflicts.  
 
And then, of course, competitive interests in others – if you’re lowering peak usage of
peaking generators by putting in demand response, there’s a lot of people out there who own
those peaking generators that would rather run them more than less, and so there are going to be
competing interests and you’re going to have to be concerned about that.  
 
All of these areas in the country that have these ISOs and RTOs, Independent System
Operators or Regional Transmission Organizations, they all have stakeholder processes.  Those
stakeholder processes are ones where they put in place proposals to do things like demand
response that they bring to us at FERC then.  There are not, as you can imagine, a lot of
consumers or a lot of advocates for the demand side of all these things in those stakeholder
processes because those people who are either small businesses or are starting out in that area, or
the consumers themselves or consumer advocates, typically don’t have the time, money, and
effort necessary to participate fully in those processes.  
 
So you have competitive interests that play a very big role in these stakeholder processes,
where we’re putting these particular tariffs in place in these wholesale markets to allow demand
response and other benefits to consumers to flow through, but it’s an uphill battle.  We’re making
a lot of progress fortunately, but FERC has been working on this for a number of years and it’s a
sort of a step-by-step process.  
 
And here’s the final thing we need, is some national leadership.  We really need an
energy plan.  We need a plan that ultimately says we have to have an intelligent energy system
coast-to-coast, nationwide.  Let’s get the states; let’s get the federal government together.  Let’s
determine how we’re going to pay for this and how we’re going to put it out there.  National
leadership would ultimately go a long way to do that.  
 
And with that, I think I’m finally there.  Thank you.  (Applause.)  
 
So I think the most important part of this – and I’m sorry I’ve gone on so long here, but
there’s a lot to talk about – is hopefully the questions and comments and concerns that you may
all have, and so I would be happy to take some and have some time to do that.  Yes, sir.  And
there’s mikes here so everybody can hear, or if you want to speak up loud – either way – I’d be
happy to respond.
 
Q:  Bill Rodenberg, Energy Matters talk radio.  Earlier in your talk you used the term
conservation and demand response in the same sentence.
 
MR. WELLINGHOFF:  Yes.
 
Q:  Were you equating the two?  In other words, typically demand response is the turning
off something or turning on a generator in response to peak demands.  Conservation, on the other
hand, would be reducing the demand 87/60.  Are those two the same thing?
 
MR. WELLINGHOFF:  First of all, I wouldn’t say conservation is 87/60, and I actually
make a difference between – I would differentiate between demand response, energy efficiency,
and conservation.  I think they’re all different.  Let me explain to you what I mean by energy
efficiency and what I mean by conservation, and then we’ll go on to demand response.
 
Conservation is when you walk out of the room and you turn off the light.  That’s
conservation.  You can actually do that manually or you can have an occupancy sensor on the
wall that knows you’re not there anymore, and it turns off the light, and that’s conservation. 
Energy efficiency is putting a more efficient light bulb in your light fixture.  That, I would say, is
all the time that that light’s on it’s being more efficient.  You’re getting the same lumens out, in
essence the same services to the room, but you’re doing it with less input of energy in. 
Conservation is you’re not getting the services at all or they’re lowered services, and it’s a choice
to do that.  So that’s the difference I see between energy efficiency and conservation.  
 
Demand response is a specific response by a customer to usually a peak load condition to
reduce that peak, and it could be done with energy efficiency or demand response – excuse me,
energy efficiency or conservation, either one.  For example, let me tell you how it could be done
with conservation.  You could go to the panel box in this hotel and you could go to the lighting
circuits in that panel box and you can put on a device that, based upon the control of PJM, would
gradually lower all the lights in this facility during 10 percent during the peak.  That would be
conservation.  It wouldn’t be efficiency because you wouldn’t be changing the load-using
devices at all, but that in fact would be using conservation to do demand response.
 
You could do the same thing with energy efficiency by putting in more efficient lamps –
bulbs in all the lamp fixtures, but that would be, you know, sort of a constant thing.  You
wouldn’t need the control from PJM, for example, to do that.  So that’s how I differentiate
between the three.  
 
Q:  Point taken.  Just to follow up on that, when you’re talking about an energy consumer
reducing or making a capital investment to reduce their energy costs, you add up all the sources
of revenue.  Demand response efficiency would be one source of revenue.  Is there any – I
understand these markets are still evolving, but is there any connection or any exclusivity or
anything that precludes greenhouse gas emissions credits with the demand response efficiency?
 
MR. WELLINGHOFF:  No, I think that’s another revenue stream that, once that is
available through a cap-and-trade or some other system, if it is available by that means, should
be another revenue stream.  You’ve got a revenue stream of demand response reductions in the
wholesale markets that will reduce wholesale prices.  That’s another revenue stream.  And then
there’s actually a third revenue stream, and that could be local distribution congestion at the
distribution level, but the distribution utility should be compensating individuals for if in fact it’s
reducing loads at that distribution level that in fact saves costs as well.  So there are multiple
revenue streams that could come in to help consumers with respect to making investments in
energy efficiency and conservation.
 
Q:  My name is Mark Lively, Utility Economic Engineers.  Smart Grid, sounds like
SCADA on steroids.
 
MR. WELLINGHOFF:  That’s one aspect of it, yeah, but – 
 
Q:  I mean, everything that you’ve talked about in the Smart Grid can be considered to be
covered by SCADA except it’s many times more involved – thousands of times more involved
than most SCADA systems.  But in your last slide you showed the ISO coverage of North
America and you talked about the hindrances to the Smart Grid, and it seemed to suggest that the
lack of ISO coverage was a hindrance to the Smart Grid.
 
I asked today on the Internet for some examples of utilities or organizations that used
backup emergency generators such as might be in a hospital or a hotel to save the system.  I got
one response from New York and he said, well, Southern Company has a great program.  No one
mentioned the ISOs.  They mentioned one of those white areas on your thing.  Do you see that
the people like the Southern Company could indeed not be a hindrance but actually be providing
help for the implementation of the Smart Grid.
 
MR. WELLINGHOFF:  Well, it depends.
 
MS. WERTHEIM:  Jon, can you explain what SCADA is for those who don’t know?
 
MR. WELLINGHOFF:  Sure.  Well, SCADSA is basically a communication system –
help me with the acronym.  What is it? 
 
Q:  Supervisory control and data acquisition.
 
MR. WELLINGHOFF:  Acquisition, okay.  And so – 
 
Q:  So supervisory control sends a message out.
 
MR. WELLINGHOFF:  Right.
 
Q:  Data acquisition brings the data back.
 
MR. WELLINGHOFF:  Right.  And ultimately it depends on what you do with that data
which is the key and how you would use it both all the way from the load level all the way up to
the transmission and grid control level.  But the only reason I mentioned and showed those
organized wholesale markets, the ISOs and the RTOs, is because they actually have tariffs that
will pay you to do demand response.  Southern Company doesn’t have a tariff per se, but they
may have a program, okay, that might pay a consumer for certain types of demand response
activities.  The question is whether or not that program is really market based in the sense that it
actually pays the consumer the full value of the benefit that that consumer brings by doing the
demand response.
 
Now, Southern Company could – they could choose to do that.  There is no prohibition
form them doing that.  They could put a tariff in place that would say to the consumer, you do
this action in our service territory.  It has this level of benefit and you will be paid this price,
which is equivalent to the market price benefit.  I know that in fact somebody in the PJM area
gets the market price benefit because it’s a market-based tariff that in fact will give them that
benefit based upon how the market operates in PJM.  So all I’m simply saying is you’re kind of
leaving it up to the good graces of Southern Company to ensure that they’re going to give you
the full value of what that certain action is versus in PJM it’s the market that’s – 
 
Q:  Are you saying that the state regulator wouldn’t enforce that, because that’s – 
 
MR. WELLINGHOFF:  Well, the state – 
 
Q:  – who would enforce the Georgia power tariffs and the – 
 
MR. WELLINGHOFF:  Yes, they’d enforce it but the question is how often do they have
to review it?  The market reviews itself every second, okay?  The market’s operating and
changes the LMPs and PJM like that, okay?  You can’t have a regulator sitting on top of
Southern Company, you know, minute by minute saying, okay, are you paying them now what
it’s worth to do what they’re doing?  I mean, it’s – you know, I guess it could be possible but it’s
not practical from a standpoint of actually making it operate like a market to ensure that the
consumer’s getting the full benefit of the market.  That’s all I’m saying.  It’s nothing negative to
Southern Company; it’s nothing necessarily positive to PJM.  It simply says that the market is
going to be more efficient than some – believe me, I know the market’s more efficient than
regulators – the market is going to be more efficient than a regulator – is going to have to
periodically approve and review what a certain tariff rate is. The tariff rate for PJM is the market. 
Whatever the market is for demand and response services, ancillary services, that’s what you get
paid by bidding in during that market day.
 
Q:  Okay.  Thank you.
 
MR. WELLINGHOFF:  Thank you.
 
Q:  David Comos (sp) from Suntech.  One of the – 
 
MS. WERTHEIM:  Louder.
 
Q:  Is it on now?
 
MR. WELLINGHOFF:  Yeah, it’s on.
 
Q:  One of the largest costs associated with the system is risk, the various types of risks.
 
MR. WELLINGHOFF:  Yes.
 
Q:  You were talking about standards being set but you didn’t state a date.  You
mentioned Whirlpool coming up with these intelligent appliances, but Whirlpool could be the
only one using their standard and the industry moves to another area.
 
MR. WELLINGHOFF:  Right.
 
Q:  At some point, is FERC or somebody else going to say, we will have a set of
standards in place on such and such a date for the industry and the system will be able to accept
these standards, and then we’ll move to version two 10 years down the line or 15 years down the
line.  If not, you end up with everybody wanting to go use their own standard – Zigby (sp) or
whatever else. 
 
MR. WELLINGHOFF:  That’s right, and that’s a very important question.  And I’ll tell
you truthfully, I can’t remember what the 2007 legislation says about timing of the standards, but
the National Institute of Standards is developing the standards on a consensus basis.  How long
they take to do it – again, I can’t remember if there’s a specific date that they were supposed to
report to FERC or not.  I’ll get that for you.  I will tell you that FERC is doing everything we can
to try to move them along.
 
Q:  Does FERC have the authority to set a date?
 
MR. WELLINGHOFF:  No, we don’t have the authority to set a date, but I’ll tell you
something else we’re trying to do that I think makes sense.  We’re trying to see if the National
Institute of Standards will set the standards from the top down – in other words, if they’ll set
them from the RTO ISO level as to what those operators have to see in communications coming
to them from all these things below.  That will set the standard for everything below, instead of,
you know, going to the appliance level and saying, okay, what do we want to do here?  Let’s go
up here and see what we need for New England, New Jersey, PJM, Cal ISO, et cetera to do this
kind of stuff, communicate back and forth in an open, interoperable way, that that will then
hopefully drive down what will be necessary at the bottom.
 
But I agree with you fully.  If we don’t get this together quickly, if we don’t get it
together in a way that appliance manufacturers, automobile manufacturers, anybody who’s
making a consumer appliance can understand and participate and incorporate this into their
products, then it’s going to be very difficult to do.
 
Q:  Thank you.
 
MR. WELLINGHOFF:  It’s a big issue.
 
Yes, sir.
 
Q:  Yeah, I’m thinking about all those 135 – 
 
MS. WERTHEIM:  Name.  What’s your name, please?
 
Q:  Oh, Tom Sheehan (sp) of National Renewable Energy Lab.  About the 135 million
meters that are out there, the old-fashioned last-century grid – 
 
MR. WELLINGHOFF:  Yes.
 
Q:  In the bad old days, at least the equipment in a typical person’s household, and in
many factories too, was pretty forgiving of glitches and irregularities on power supply.
 
MR. WELLINGHOFF:  Right.
 
Q:  If you go to the modern system where there’s all this digital interchange of
information, is it possible that this will cause an enormous increase in the requirement for power
quality?  And if so, how will that be addressed?  And will the low-level industrial or residential
user be able to absorb the additional cost of that?
 
MR. WELLINGHOFF:  Simple answer and the honest answer is I don’t know, and it
may.  I mean, it ultimately may – I’m sure it’s something that the National Institute of Standards
is thinking about.  It’s something that we need to think about on a wider basis.  You know, the
amount of digital equipment we have in our house right now with computers and advanced
electronics and so forth all does require a better power quality.  And so ultimately there’s going
to be a need for sensing devices to maintain that quality in a way that it doesn’t take out these
new things that are installed.  I would agree with you fully.
 
Yes, sir.
 
Q:  Paul Rorvy (sp), Army Operations staff.  You talked about a number of things the
FERC is doing to address the power reliability issue out there, which is something that the
military certainly is interested in right now.  You’re looking at regulation policy that addresses
reliability all the way down to consumer technologies to control their demand.  Where do you
see the opportunity for DOD to make the biggest impact on this reliability issue, and in particular
as it relates to military installations?  Is it participating in some of these task forces?  Is it being
part of the regulation process?  Is it doing some war-gaming to help understand, you know, what
would be the most useful, or is it just consumer behavior in the way that we run our energy
systems and our technical systems?
 
MR. WELLINGHOFF:  Well, I hate to be so general but I think it’s really all of the
above.  Any point of entry that you can see I think the military ought to take advantage of it.  To
the extent that the National Institute of Standards is working on these standards, I think it would
be good for the military to be involved, and I don’t see any – you know, I think DOE would
welcome it.  DOE is the one who sort of convenes these different task forces that I mentioned.  
 
MS. WERTHEIM:  Jon, who would they get in touch with – (off mike, inaudible) – have
those conversations?
 
MR. WELLINGHOFF:  Probably the best person that I know of name-wise is somebody
at FERC who is our contact person to the National Institute of Standards, and that’s a gentleman
by the name of Ray Palmer, who is in our new what we call Energy Innovation Sector.  Ray is
head of that sector and he is the one who is responsible for interfacing on these standards, both
the National Institute of Standards and on these DOE advisory committees.  He’s the FERC
member on the advisory committee.  So Ray would be a good point of contact for you.
 
Beyond that, you know, there’s another standard-setting body for reliability specifically. 
It’s called NERC, the National Energy Reliability Council, that FERC selected as our reliability
organization when we were given authority under the 2005 EPA Act to do reliability.  NERC has
a number of stakeholders that also develop consensus standards that are then submitted to FERC
for final approval.  So you might want to get a hold of Rick Sergel at NERC and see to what
extent the military could interface with their activities, because they’re more ongoing on all
aspects of reliability whereas the National Institute of Standards and these DOE advisory
committees are specific to this Smart Grid energy intelligence idea, and they’re sort of narrower
in that regard.  But NERC is the general national reliability organization that FERC has
designated to develop standards and to enforce reliability throughout the country through a
number of regional enforcement entities that NERC has designated around the country –
reliability councils that they oversee.  So there may be a role for the military with respect to
NERC’s activities also.
 
Q:  Okay, thank you.
 
Q:  Hi, I’m Curt Wexel.  I’m with Army Installation Management.  I had a couple of
concerns on the way that you were defining market-based compensation for demand and control.
 
MR. WELLINGHOFF:  Okay.  Sure.
 
Q:  Having an ISO, I don’t see how it’s necessary that you calculate three times a second
what the value of the demand reduction is in order to have a market-based system; that working
with a power company, a market-based system is a free exchange or agreement between a vendor
and a consumer.  In the case of my power company, when they said they would give me $4 a
month off if they’d let me put a controller on my water heater and interrupt it for up to a given
number of hours per month, they made the investment, I accepted the terms and conditions and
the inconvenience, but they also accepted the risk involved with putting in that unit for the
savings that they got.
 
So I don’t see why, as a consumer, I need to have a compensation that changes with the
actual load for it to be a market-based incentive, or why you need an ISO to do that.
 
MR. WELLINGHOFF:  Well, I’m just saying it’s not market-based in the sense that it’s
not changing as locational marginal prices will change on a virtually minute-by-minute basis
within PJM.  And that’s how the prices are set for these various services.  Now, certainly if you
chose, there’s nothing wrong with you making an agreement with your local distribution utility
to have them pay you a certain amount for a device that they put in and control.
 
Q:  But that’s still a market-based decision and contract.
 
MR. WELLINGHOFF:  It’s a decision – yeah, it’s a decision between you and them.  All
I’m suggesting is there may be more value in you doing it in some other way.  And you need to
have the information to decide.  I’m sure they didn’t come to you and say, you can, through
some aggregator – Internoc or Converge, or I can name, you know, 10 other companies that
aggregates consumers together.  You can, if you want to, take the deal from these people or you
take the deal from us.  I mean, I’m sure they didn’t tell you that.  All they did is say, this is our
deal.  You know, a take it or leave it kind of thing.
 
Q:  They work out the economics and they decide how many systems they’re willing to
invest in and what incentive they need to offer in the free market to get enough consumers to
sign on. 
 
MR. WELLINGHOFF:  Right.  All I’m suggesting is there’s lots of other non-utility
entities that are aggregators that do the same thing and you should have the freedom to decide
which one to choose.
 
Q:  Obviously I’m certainly agreeing with you.  On a larger scale, if you’re a major
industrial complex or a major user, you might want to be more involved with getting a fair price,
but I’m just saying that the market can work without all the details – 
 
MR. WELLINGHOFF:  Sure.
 
Q:  – calculation and time changing.
 
MR. WELLINGHOFF:  I agree.
 
Q:  Thanks.
 
Q:  Hi, Commissioner.  Thanks for your time this evening.  My name is Chris Slough (sp)
with WRI.  I have a somewhat related question.  Earlier the slide that showed the total cost of
Smart Grid or intelligent infrastructure, it put it around 60 billion (dollars).  
 
MR. WELLINGHOFF:  Right.
 
Q:  Now, I don’t remember – you said roughly a three-year payback.  What’s interesting
to me is if I understood correctly, most of that 60 billion (dollars) will probably fall on utilities
and grid operators, and the payback was based on the benefit to the consumer.
 
MR. WELLINGHOFF:  Well, let’s put it this way:  All of it will fall on consumers.  The
consumer pays for everything.  Let’s remember that.  It all falls on consumers.  Every dollar
investment in the system and a return on top of that is paid for by consumers.
 
Q:  So you see all infrastructure coming from ratepayers.
 
MR. WELLINGHOFF:  Oh, yeah, of course. 
 
Q:  All right.
 
MR. WELLINGHOFF:  Yeah, absolutely.  Consumers pay for everything.  You’ve got to
remember that.  
 
Q:  Hi.  My name is Andy Peres (sp).
 
MR. WELLINGHOFF:  I mean, I don’t know any utility that’s in the business to lose
money.
 
(Laughter.)  
 
Q:  My name’s Andy Peres.  I work with the U.S. Department of Commerce.  I actually
work with the automotive industry there in looking at how plug-ins might impact the grid in the
Smart Grid system.  I understand that a very small amount of plug-ins could provide regulatory
services for the grid – 
 
MR. WELLINGHOFF:  Right.
 
Q:  – but I also – looking at that, you know, plug-ins would also tend to remove the
valley from overnight charging.  Pretty simply, just putting a timer on the vehicle you could get
the vehicle to charge during later night hours and such.  
 
MR. WELLINGHOFF:  Right.
 
Q:  But also, looking at – I’m sorry, go back a little bit.  The demand response system is
declining returns in that the early adopters of demand response and early – early investments in
demand response will have a greater return than later on.  So the first homes that turn into – or
participate would have a larger impact than later on.  Is there – I mean, aren’t there costs to
include this information or the ability to process informant in a toaster, and would this cost be –
would it be returned for later on?  I mean, do you have to have 100,000 toasters with this
information in them?  Is there anybody looking at that?
 
MR. WELLINGHOFF:  Certainly people like Whirlpool are.  In fact, the slide
presentation or the PowerPoint presentation I got today shows me that Whirlpool is looking at it,
driving down costs to put these devices in, which I think they’re showing that the costs are, you
know, substantially reduced from what they were three or four or five years ago even with new
electronic digital capabilities, that the costs are really minimal to put these kind of capabilities in
appliances.  I agree with you that some point of saturation of – universal saturation, the benefits
to every – the total benefits to everybody are going to spread over everybody, but the total
benefits don’t change.  Still the total benefits are there, but everybody may share in a little less
benefit overall, but a $60 million investment is still going to return you 21 million (dollars) a
year even though you may be spreading it now over, you know, 100 million consumers instead
of initially over 10 million consumers.
 
Q:  Actually, the question is whether or not anybody is looking at whether or not we’re
going to be spending more money to put these into devices than is needed to receive the return
that we need.
 
MR. WELLINGHOFF:  Well, yeah, and that I think is a good question.  Again, I think
the appliance manufacturers are certainly going to make that decision as to whether or not they
think they can sell the appliances with the incremental added cost of incorporating this
technology into it.  To the extent they can, I think they will.  Beyond that I don’t think anybody
is looking at it in – I don’t think anybody is looking at it in sort of a holistic way to say, gee,
Whirlpool, maybe you should put this in dryers but you shouldn’t put it in an iron.  I don’t think
– I’m not sure anybody’s doing that.  In fact, I want to ask Whirlpool that question.  But that’s an
interesting question.
 
Yes?
 
Q:  My question in a way is kind of related.
 
MS. WERTHEIM:  Your name?
 
Q:  Oh, Steve Bruckner with Sierra Club.  The cost of the system that you’re talking
about of course doesn’t include any of the appliances that would take advantage of this.
 
MR. WELLINGHOFF:  Right.  Right.
 
Q:  They’re still left as an exercise for the consumer.
 
MR. WELLINGHOFF:  Right, which I’m assuming will take place over the change-out
of those appliances, just like the change-out of automobiles from current to plug-in hybrids will –
yeah.
 
Q:  Right.
 
MR. WELLINGHOFF:  So that’s not par of the cost.
 
Q:  So it takes significant drivers because a plug-in hybrid people will get not because of
this particular feature but because they want the benefits of the gas price improvements.
 
MR. WELLINGHOFF:  Right.  There will be multiple benefits.  That’s right.
 
Q:  But in all the other appliances it’s just changing out over time.  You know, the
amount of savings doesn’t sound that extraordinary.  But, you know, for network – I mean, here
the cost will be incurred by all the consumers before they have the appliances.  In other words,
the state utility commissions will be – 
 
MR. WELLINGHOFF:  Not necessarily.  I mean, again, if it’s rate-based it could be over
20 years.  So, I mean, typically utility rate base is something – 
 
Q:  Okay.
 
MR. WELLINGHOFF:  – so, no, it won’t be incurred by them before they have the
appliances certainly.
 
Q:  So they could charge it out over a long enough period of time – 
 
MR. WELLINGHOFF:  Yeah.
 
Q:  – that it would kind of get lost in the – 
 
MR. WELLINGHOFF:  Yeah.
 
Q:  All right, well, that does improve things because I’m thinking, you know, the
consumer would not – 
 
MR. WELLINGHOFF:  Well, the consumers aren’t going to pay 60 billion (dollars) up
front.  
 
Q:  – experience the benefits.
 
MR. WELLINGHOFF:  No, they’re not going to pay 60 billion (dollars) up front.
 
Q:  Right.
 
MR. WELLINGHOFF:  It’s going to be in rates – embedded in rates and it will be paid
over time.
 
Q:  Understood.  So it would be reasonable for them to accept it.
 
MR. WELLINGHOFF:  We’ve got to pay for it like we’d pay for a power plant.  I mean,
we pay for a power plant right now.  You know, a coal plant you pay for it over 30 years.  You
can’t put that on an unequal playing field with central generation or we’ll never get there.  That’s
the whole problem we’ve had with distributed generation for so long is tried to compete against
the central coal plant but, you know, you want to pay for it today and you get to pay for the coal
plant over 30 years at utility-financed debt, and we can’t do that anymore.
 
Q:  Okay.  Yeah, I was thinking in terms of, you know, the changeover – you know, the
kind of thing he was talking about, about timers or something, about when you charge your plug-
in hybrid or whether you could have programmable timers around the house that are not
connected to the grid but just do this stuff in the evening.  
 
MR. WELLINGHOFF:  Yeah.
 
Q:  You know, like the defroster cycles or things like that.
 
MR. WELLINGHOFF:  Right.
 
Q:  You know, those seem perfectly reasonable and it would be good if they had
mechanisms like this which finally gave consumers time of use pricing so they could take
advantage of this.  They could manually do a lot around the home – 
 
MR. WELLINGHOFF:  Well, and they do things like that.
 
Q:  – without changing the appliances.  
 
MR. WELLINGHOFF:  I mean, they do have things like that now.  I mean, you can buy
a wall socket that in essence has an occupancy sensor on it so you could hook in all of your
various TV and electronic stuff that when you walked out of the room, you know, all of it shuts
off.  You don’t have the standby and all the vampire loads going into your – 
 
Q:  Right.
 
MR. WELLINGHOFF:  And you can do that.  And those are good things.  I’m not saying
those are bad things, but this is sort of a more advanced, automated way – 
 
Q:  Right.
 
MR. WELLINGHOFF:  – for consumers to not have to think about that.
 
Q:  Right.  It would be good if there were these retrofit-type mechanisms because those
timing devices are less than 20 bucks.  They control all sorts of things.
 
MR. WELLINGHOFF:  Yeah, I think there are and there will be more of them.
 
Q:  Yeah.
 
MR. WELLINGHOFF:  Yeah.
 
Q:  Thank you.
 
MR. WELLINGHOFF:  Yes?
 
Q:  Hi.  Angeline from Our Task.  You may have already covered this – I’m sorry, I came
in late – but I heard through the grapevine that if we start moving towards kind of a more locally
produced energy, things like solar panels on everybody’s roof or maybe even some type of plug-
in fuel cell or something like that, that the grid as it is now would not be able to handle energy
generation coming from multiple sources like that.  Does the Smart Grid adjust that at all, or
would it help?
 
MR. WELLINGHOFF:  Well, like I talked about – I don’t know if you saw the one slide
on being able to change the voltage taps on transformers.  That kind of Smart Grid capability
would help better integrate distributed generation where you have generation coming from
multiple sources at the distribution level so that you could maintain voltages properly and you
could operate it properly.
 
To what extent can the existing grid without that kind up upgrade take a lot of distributed
generation?  I don’t know.  It’s going to depend upon what particular distribution you’re talking
about.  There’s lots of areas that have a lot of distributed generation.  There’s places in California
and actually, interestingly enough, in New Jersey that have a lot of solar PV at a distribution
level that seem to be operating fairly well, although I’m not sure that they’re operating at
optimum level.  But I would agree with you that to make those distribution systems operate
better we should have these kinds of sensing technologies in them to see what’s going on at that
distribution level to optimize that operation.
 
Q:  But this could help to – 
 
MR. WELLINGHOFF:  Oh, absolutely would help.  The other thing all this could help
with is also the integration of intermittent renewables like wind at a central basis outside, that if
we had things like plug-in hybrids and demand response and other responsive loads that could
respond to how the intermittent loads were operating with the system, you could better integrate
those intermittent loads as well.  So you can not only integrate more distributed generation with
demand response and other sensing abilities at the distribution level and more SCADA, in
essence, at the distribution level, but you can also integrate things like wind better from centers
far away.
 
Yes?
 
Q:  Hi.  Marv Langston.  I support, among other things, a presidential advisory committee
called NSTAC, National Security Telecommunication Advisory Committee.  There have been
cross studies with your organization about the interdependence of telecommunications grid and
the power grid.  You implied, or you mentioned earlier in your discussion that that was an
interest or concern relative to where this is going, but I didn’t hear you say very much about it.  I
wonder if you had any more comments about that.
 
MR. WELLINGHOFF:  Well, it certainly is an interest from the standpoint of how we
can make the communications a more robust part of the power grid.  And I know that there’s a
lot of work with respect to communications over power line, or say broadband over power line,
and how that may be able to be integrated in the system and effectuate this.  To the extent that
we start to put up independent non-power line communication networks that are primarily for the
purpose of data transference, I think there may be multiple uses for those networks for other
communications purposes as well, and we certainly ought to think about and figure out how that
can be integrated.  And I don’t know if that answers your question per se, but those are the two
areas that I certainly have some interest in.
 
Q:  Well, I think clearly we need other mechanisms for the networks to survive.  There
probably needs to be new standards and new laws or regulations put in place related to it.  But
the big issue is the more we make the network smart the more the cyber-security threat becomes
a threat that has more capability or more power. 
 
MR. WELLINGHOFF:  Oh, that’s true.  We just have more doors for people to get in. 
There’s no question about that.  And that is a big issue as well.  Believe me, I understand that
and I believe that every step of the way we have to embed some cyber-security protections in
what we’re doing to ensure that we’re not making things worse and trying to make things better,
hopefully, because we’re in pretty bad shape right now.  We don’t want it to be any worse.  We
really definitely want it to be better because we have some severe, severe problems in the
country.
 
Q:  One thing you didn’t talk – 
 
MS. WERTHEIM:  Name?
 
Q:  Oh, Dan Yi (sp) from Cynotech.  One thing you didn’t talk as much is energy storage
technologies – 
 
MR. WELLINGHOFF:  Yes.
 
Q:  – which, you know, has the potential to really balance the grid permanently.
 
MR. WELLINGHOFF:  Yes.
 
Q:  And I want to know if you can talk a little bit more about it, like what are some of the
potential technologies out there that can achieve this end?
 
MR. WELLINGHOFF:  Well, I know there’s some experiments going on in New
England right now with flywheels that are working on energy storage.  And I know that some
large energy companies are also looking at large battery systems with lithium ion batteries. 
Those are the two areas that I’m directly aware of.  In addition to that I know that the University
of Delaware is working with, as I mentioned, plug-in hybrids to look at them as a storage
mechanism for the grid, as well as, obviously, in transportation – a car device.  I see plug-in
hybrids to have the ability for that dual role in a number of ways, but one of the problems is the
car manufacturers are very concerned about allowing those plug-in hybrids to go both ways.  In
other ways, not only charge but to discharge back to the grid.  They’ve got some real liability
issues that I think are legitimate that we’ve got to overcome, whereas a dedicated storage system
like a flywheel system or dedicated batteries you can set up to have, you know, automatic
disconnects, and they’re larger systems so you can spread the costs of those kinds of disconnects
over that larger system where the cost to do that in an automobile may be prohibitive; I don’t
know.
 
But I know that there are experiments going on with respect to storage.  I’ve seen a study
from New York.  For example, the New York ISO did a study that indicated that storage on the
New York grid system could save them – I think it was two (hundred million dollars) to $300
million a year – it was a lot of money – by just putting storage on the – just the New York system
itself.  So that’s my familiarity with storage.  I think it’s a very promising area; just a matter of
cost benefit ultimately – storage.
 
Q:  Thank you for your presentation tonight, Commissioner.  My name’s Brian Lally. 
I’m the energy program manager for the Air Force.  FERC’s order 706 on cyber-security – 
 
MR. WELLINGHOFF:  Yes.
 
Q:  – very encompassing and enforceable to the bulk power systems, but what are you
doing or what is FERC and NERC doing to create that enforcement at the local distribution
company level?
 
MR. WELLINGHOFF:  Well, we are not sure legally that we have that authority.  That’s
why the legislation that’s pending before Congressman Boucher in Congress – and I’m not sure
he’s actually got the bill out but I know it’s being written – includes that issue.  There’s a lot of
pushback from the utilities on it – 
 
Q:  Absolutely.
 
MR. WELLINGHOFF:  So we certainly could use the Defense Department’s support,
and you have provided us tremendous support, and I appreciate that very much.
 
Q:  We’re dependent on reliability as the rest of the grid and all the consumers should be. 
So it’s a matter of who can partner with whom, I think, to get at that level of the local
distribution companies to create that enhanced level of cyber-security.
 
MR. WELLINGHOFF:  Right.  And FERC also doesn’t have jurisdiction over Hawaii
and Alaska, where there’s many defense facilities, as you’re aware.  So that’s another part of
what they’re trying to add to the bill.  And, you know, again, there’s a lot of discussions and
there’s a lot of different concerns and opinions about expanding FERC’s authority in that area.
 
Q:  How long do you think it will take?
 
MR. WELLINGHOFF:  Well, they’re trying to push that particular bill through this in
session here, and if they’re successful, I think we could – FERC is very good at taking
legislation, putting regulations in place and implementing things.  I have no question we could
do it in less than six months.
 
Q:  Thank you, sir.
 
MR. WELLINGHOFF:  Yes?
 
Q:  Richard Hoy (sp) from Montgomery County.  I haven’t heard any discussion tonight
about reducing demand overall by alternative technologies.  It seems to me a very
straightforward way of getting a 15-percent reduction in electrical utility use would be through
the massive adoption of absorption refrigerators for single-family homes and apartment dwellers. 
Absorption – air conditioning – of different technologies.  It seems that whether we’re talking
about these different technologies, we’re talking about different industry characters, nonprofit or
for-profit – that have, as a basic interest, their self-preservation and the use of their type of
energy.
 
MR. WELLINGHOFF:  That’s right.
 
Q:  So if you could talk a little bit about that and about how we can get to analyze this
problem from how many BTUs do we consume to get a BTU of service, rather that just the cost
and how to make a fancy system for this.
 
MR. WELLINGHOFF:  Right.  I mean, overall reduction in energy usage by enhancing
energy productivity.  It’s an area that I have a lot of experience in.  I’m not going to spend a lot
of time giving you an answer though because it’s an area also that FERC has very little sort of
jurisdiction over.  It’s the end-use appliance and the end-use customer and the manufacturer of
those appliances.  But I would agree, there’s all kinds of technologies out there – I used to
represent some of them when I was in private practice – that are much more advanced and much
more efficient than what is commonly purchased by the consumer.  Notice that I didn’t say not
available on the market.  They’re available on the market but they’re usually smaller companies
who are in an infrastructure – company infrastructure system – industry infrastructure system
that is very restrictive.  
 
Air conditioning is one.  I know a lot about air conditioning.  I’m not completely familiar
with the technology you’re talking about but I’m familiar with the technology in residential air
conditioning that basically uses a water-cooled evaporator coil in a standard condensing air
conditioning unit that’s twice as efficient as anything else on the market right now, except for
maybe some of the more advanced carrier systems.  But that particular company only makes
about 10,000 units a year and there’s 7 million air conditioners sold a year in this country, and
there’s, you know, a number of major manufacturers – Carrier, York, Trane.  There’s three or
four major manufacturers who make the bulk of that.  
 
So for a small company to break in and get a market share with a disruptive technology is
very, very difficult.  We need to figure out in this country how to change that.  It’s not a matter
of necessarily picking winners and losers; it’s a matter of identifying promising disruptive
technologies that can have huge impacts on overall energy usage and demand and figuring out
how to make them more competitive in markets that have restrictions, that are not really fully
operational markets, for a number of different reasons.  I’ve been thinking about that issue and
trying to work on it for many, many years and I’d love to hear any answers that you may have,
and I have some of my own ideas, but thank you.
 
Are we done, Mitzi?
 
MS. WERTHEIM:  Yes.  I want to thank you all for hanging out this long.  It turns out
the air conditioning in the building is completely out.  So for those – I’m amazed that there’s so
many men that still have their jackets on.  Anyway, two quick announcements before we start. 
Our next meeting will be on October 20th.  I’m still working on who’s going to be our speaker, so
we hope you all come for that. 
 
Jon, this has been an amazing evening in terms of, I think, what we’ve all learned, and
the number and the rich questions that we’ve gotten from this audience.  So I want to thank first
of all the audience.  Secondly, Frank Anderson, who I lured into coming and changing his plans
so he could do our introduction.  And to Jon, you’ve done a fabulous job.  Thank you very much. 
(Applause.)  
 
I hope to see you in a month.  Thanks.
 
(END) 

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