Load forecasting is not going to be
any easier. Some still insist on asking when
future loads will return to “normal” and, in
their mind, it mostly depends on when
there is “full” recovery. But that’s not all.
Finally, after two decades of increasing talk
about demand-side management and distributed
resources, the smart grid is about
to emerge. What that really means, nobody
is really sure but it is likely that we will see
between 70 million and 90 million of new
so-called smart meters being installed by
2020 – or between 44% and 57% of the 159
million meters in operation by then. This
trend will not only involve the 70+ large
IOUs that we have in the US but also a couple
of hundred municipalities and co-ops.
Utilities are intent to use the new metering
capabilities to deploy new “dynamic” rate
structures (such as revised Time-of-Use
rates, Critical Peak Pricing, or Peak-Time
Rebates) designed to spur demand
response (DR) in a way that has never been
seen before. Briefly, estimates tend to range
between 50 GW and 100 GW of additional
DR capability by the end of the decade.
WHERE IS THE LOAD FOR UTILITIES?
Of course, the devil is in the details.
There are various types of smart meters
being installed and different levels of control
capability being deployed. In fact, there
are very few smart grid deployments that
look alike. Second, we still don’t quite know
how much DR will be load control (much
more 0-1) versus dynamic rate pricing
(much more elastic). Third, the new
dynamic rates must be designed and
approved by the relevant public utility commissions
(PUCs) – a process that can take
some time and result in compromised program
features. Then, we have to see
whether customers respond the way the
models say they will. Of course, the models
do not all agree and estimates of peak
reduction triggered by dynamic rates vary
between 6% and 15% depending on how
steep the rates are during critical times
when peak reduction is most desired. Load
reductions due to time-of-use rates tend to
be smaller – between 2% and 6% for customers
without high air conditioning loads
and between 6-10% for customers with
either high winter (electric heating) or high
summer consumption. In large part, these
models rely on the results of early pilots.
But after reviewing nearly 20 of these, it is
hard to conclude that they represent a
strong statistical sample (mainly stemming
from differences in weather conditions, rate
structures, meter capability and customer
segmentation). Pilots also do not give much
information on the robustness of DR: is
load shedding a sure thing from year to
year; does it grow; and how will it play withnew retail prices in unregulated retail
areas? Likewise, new rates and smart
meters should trigger increased energy
efficiency, but it is not always easy to estimate
that component separately (and in
some cases, it also means reduced gas
usage).
So, we don’t really know… plus, the
impact will be very utility specific as we can
see from utility filings with expected paybacks
on their smart grid investments often
in the 7-10 year range. Some utilities may
experience a 8-12% DR-induced load reduction
while others next to them may be more
in the 5-8% range as the result of not only
dynamic rates but also the deployment of
in-house displays and controls. The range is
even wider when one looks at the Brattle
Group’s estimates of DR-induced peak
reductions; these range between 4% and
24% with an average of 11%. At the end of
the day, though, there will be increased DR
and, hopefully, this will be a one-time
durable investment in customer empowerment.
Now, for utilities, this may also mean
lower revenues in some cases and increases
in the fixed component of fixed rates –
something called “decoupling” which is not
really DR-friendly.
Having said all of this, the 50-100 GW
estimate for added DR may not look that
bad even though RTOs are likely to seriously
evaluate the reliability of this emerging
DR capability. Still, it can make a difference
as evidenced by a recent PJM simulation
that showed a recommended DR cap of
8.5% of system peak which would amount to
a very respectable 16 GW of deemed-reliable
DR capacity in that pool at this point in
time.
WHERE IS THE LOAD FOR GENERATORS?
Know your customer! it does help.
Unfortunately, generators (and their regional
councils, by extension) were used to rely
on utility load forecasts. Now, that will be a
bit harder not just because of smart grid
roll-outs but also because of the impact of
growing wholesale renewable resources,
from both wind and solar. There too, there
is a wide range – roughly anywhere
between 100 GW and 150 GW of wind in
place by 2020 subject to the amount of
transmission capacity that can be invested
in. These new resources deliver an intermittent
load causing wide fluctuations but
otherwise requiring more ramp up system
flexibility. There may be more gas capacity
back-up, and if possible investments in new
power storage facilities. The most recent
NERC scenario assessment (released in
late 2009) assumes 155 GW of additional
renewable capacity in 10 years, calling for
up to 40,000 miles of additional transmission.
The result is a 15% penetration for
renewables – not the 20% that some have
been asking for – but closer to the average
of all RPS state mandate targets announced
(or extrapolated) for 2019/2020.
Even then, the NERC analysis concludes,
this would trigger many changes:
• Minimum generation limits during
light load conditions
• Increased ramp requirements and
out-of-phase ramping
• A much better coordination
between day-ahead ancillary
service markets and wind forecasts
and real-time monitoring of wind
output
• Additional operating reserves.
On that last point, the reserve margin
increases could be substantial in some
regions. Based on the NERC analysis, I estimate
the following impact in terms of needed
reserve margin increases:
• A jump from 13% to 28% in MRO
• From 20% to 27% in NEPOOL
• From 28% to 37% in SPP
• From 15% to 22% in SERC
So, it roughly is an increase of at least
40 GW in additional reserve margin that
would be required in that 15% renewable
penetration scenario.
Our own analysis shows that some
states are likely to be much more impacted
than others by the combination of high
renewable requirements and extended
smart grid deployment. We found that the
15 most impacted states would be, in
decreasing order of severity, Connecticut,
Maine, California, Maryland, Minnesota,
DC, Texas, New York, Ohio, Pennsylvania,
New Jersey, Delaware, Nevada, Utah and
Vermont. Clearly, the threat is nationwide.
These states are all over the US, not in one
region.
Another complication is the impact of
carbon legislation. If it is drastic, it will trigger
some changes in dispatch intra- and
inter-dispatch patterns and even reallocation
of existing generation capacity. For
example, a PJM study concluded on a
range of impact between $7/MWh and
$45/MWh by the mid-2010s, based on a
carbon price between $10/ton and $60/ton.
While that analysis was centered on the
kind of bills debated in 2009, and while the
more recent bills are different, it still is an
indication of the kind of impact range that
is at play. There is now more and more talk
of plant closures for older mid-size coal
plants. While these plants have survived
much longer than any consultant ever
thought, we may now approach the time
where these plants finally shut down, not
just on economics but also because their
owners may be able to get in exchange
accelerated permits for new super-efficient
gas generation. To give an idea, that could
be a swing of 20-50 GW if carbon prices
exceed $30/ton by 2020. It also means that
congestion costs could significantly change
in amount and location for several East
Coast RTOs.
So, generators have to deal with a
triple moving target: utilities that experience
more elastic loads in balancing areas
exposed to more volatile renewable
resources and with the possibility that the
existing fossil-fired capacity does not quite
behave like it used to. While any one of
these factors is not uncommon, and even
combining two of them is not unheard of,
dealing with all three promises to be interesting.
To illustrate the point, we show on
Exhibit 1, the range of uncertainties that
are involved and estimate what we call the
potential for load imbalance. We also know
that in even the best organized RTO markets,
small imbalances can trigger wide
wholesale price volatility. That analysis
shows that we would need another 20-50
GW of new (mostly gas-fired) fossil capacity
– which is double the capacity of 20 GW of
new combustion turbines and combined
cycle capacity shown in the latest EIA run
(issued in early 2010). We should also say
that we don’t see much utility power storage
capacity developed by 2020 – maybe 1 GW.
REASONS FOR HOPE
The estimates we show are large
enough to suggest that there will be a need
for mitigating measures.
First, utilities will hopefully invest and
be successful in the use of analytics to track
demand response as well as they can. So
far, this has not happened but this will
become a must by 2012-13.
Uncertainty Factor |
Unit |
2020 Outcome |
Smart metering development |
Million of units |
70-90 |
DR peak reduction |
% |
10-15 |
DR peak reduction |
GW |
50-70 |
DR load reduction |
% |
5-10 |
DR Load Reduction |
TWh |
200-400 |
Additional Renewable Development |
GW |
50-100 |
Dislocated generation
(due to carbon legislation) |
GW |
20-50 |
Potential Load Balance Impact |
GW |
20-70 |
Fossil Capacity Needed to offset |
GW |
20-50 |
Exhibit 1
Second, we can
trust at least some utilities to want to
become smarter in yield management and design new rates, especially in unregulated
areas. Utilities will find out that not all DR
is to be desired. Right now, though, we’ll
take any DR. In addition, we should count
on private DR providers to really mine the
commercial market. We can already see
signs of increased activity on this front with
major corporations, such as ABB, AREVA,
Cisco, GE, Honeywell, Johnson Controls,
and Schneider Electric, acquiring smaller
outfits that offer automated DR services
and aggregated DR portfolios. This too
should mushroom in the 2011-2013 period.
Third, by the mid 2010s, utilities will
invest more in the other part of their operations
that has been neglected: active distribution management (ADM) which will
include increased investments for:
• automated feeders and RTU line
monitoring
• faster restoration – so called
Automatic Sectionalizing &
Restoration (ASR)
• More adaptative volt/VAR control
– new approach is called SCADA
controlled Volt-VAR.
• More capacitors.
By 2015, ADM investments will grow
and could average $4-5 billion annually by
the end of the decade. Of course, some
ADM investments could be done now but
most utilities find it hard to ask for more
monies from the PUCs and customers on
the top of individual smart metering programs
that can cost hundreds of millions of
dollars when they involved a million or
more new meters. For example, PG&E’s
smart grid plan calls for deploying some
4.6 million new meters at a cost of about
$2.2 billion. Also, in all fairness, ADM
investments are best done when utilities
have a better sense of true demand
response, thus the need for better analytics
again.
With ADM and better grid sensors,
distribution companies may be able to
achieve true “Management by Wire”.
That’s the “Holy Grail” when utilities can
use their meter data management systems
(MDMs) to continuously balance on one
hand a fluctuating supply (at least in terms
of price but also quantity available if there
is a large component of renewables) and a
malleable demand that is subject to a true
demand-responsive rate structure well supported
by regulators. At that point, utilities
will also be able to better incorporate in
their integrated resource planning strategies,
new portfolio management tools to
optimize smart grid commercial operations
with demand side optionality and the incorporation
of Virtual Power Plants, distributed
generation and microgrids as an
increasingly larger and more viable
resource category. Of course, that highroad
scenario does not cover vegetation
management which will still have to be
done in a more conventional way…..
But there will be other trends to help
solve the equation:
1. New Intra-RTO “backbone” transmission
will become a major issue that will
prompt consideration for larger RTOs
2. Utilities and RTOs will have to figure
out ways to price new ancillary services
and new storage capacity
3. Repowering on brownfields may
see a second life – that’s flexible gas-fired
load balancing capacity near the loads
4. The business for turbine O&M
services by both OEMs and third-party
providers will continue to be a very good
one indeed as more CTs and CC machines
experience increases in start-up requirements
to balance the loads.
So, it won’t be easy. Plus I forgot to
mention that by 2020, there may be the
emergence of electric vehicles. The impact
on the grid is not known either… but that’s
for another decade to sort out. |