The crisis is a double whammy for the US power
sector: reduced economic activity means lower sales
and dropping commodity (oil, gas and coal) prices
mean lower wholesale power prices. You combine the
two and it spells lower revenues, decreased earnings
and reduced asset valuations for unregulated (i.e.,
merchant) assets. However, it is not just the crisis that
will have an impact on the US power sector but also
the new laws, polices and regulations that will be
enacted under the Obama administration. In addition,
states will make moves of their own, continuing a
trend that started in 2005 when it became clear that
the Federal government was not going to do much
during the second mandate of President Bush.
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As a result, we foresee serious impacts for both
investor-owned utilities (IOUs) and independent
power producers (IPPs). Overall, IPPs will have a
much tougher time in the next 2-3 years but they are
used to it since they just went through a terrible period
in 2002-2005; those who survive know that they will
enjoy a stronger recovery later, especially if they
develop wind projects.
Demand for electricity will drop
through at least 2010 and further demand
growth will be kept in check by increased
energy efficiency and demand management
efforts. As a consequence, many generation
projects will be delayed or cancelled and
new plant additions – beyond what is
already under way - will not be needed until
past 2015 in several regions of the country.
Greenfield project development activity can
be expected to drop by nearly half for fossil
fuel plants. It will be a whole different story
for renewable plants which will enjoy
strong support but the ones that will benefit
from it will not be for the most part your
traditional IPP players.
In the following, we try to quantify
these impacts on both utilities and IPPs
over the next seven years.
LOWER AND THEN SLOWER DEMAND
The first impact is reduced electricity
usage for the next 2-3 years – up to 350-400
billion kWh less in 2010 which is a 9% drop
(or $30 billion in sales) compared to was
what projected pre-crisis. That’s not small
potatoes: the crisis could mean a sales volume
loss of over 1,100 billion kWh through
2011 – that’s over $100 billion in revenues
less than what IOUs were counting on
when they were preparing their capital
expansion plans about a year ago.
As a result, we believe that, in spite of
the numerous rate increases that were
approved in 2007-2008, IOUs’ revenues for
2009 will be 3-4% below 2008 levels. We also
forecast that utilities’ earnings will drop by
at least 5%-8% this year. In our analysis, we
find that about one IOU out of three will
see its 2009 earnings drop by 20% or more
and almost half will see earning drops over
10%. So, we project that the amount of cash
that IOUs will get from operations will drop
by $12-18 billion in 2009 – that’s a 25-30%
cash flow reduction right there.
Longer term, we see the potential for
a more permanent reduction in electricity
use if all the investments in energy efficiency
and automated metering infrastructure
(AMI) that are currently being considered do pay off as advertised. In addition to
launching a huge weatherization effort, the
government plans to invest billions of dollars
in retrofitting existing public facilities
and has signed up with 16 energy-saving
companies to execute up to $80 billion of
energy efficiency upgrades. Likewise, the
talk about smart grids has reached hype
conditions. Nonetheless, even after trimming
by half the announcements that have
been made, it is not unreasonable to see
the penetration of AMI jump to 40-50 million
meters by 2015. How that would translate
into peak demand shedding and actual
kWh savings remains to be seen but, even
after haircuts, it may mean 30-40 GW of
additional demand-side management and 4-
5% savings in electric usage. In that case,
demand growth is then much more in the 1.1%/year range rather than the 1.4-1.6%
range we got used to recently. Over time,
this adds up.
While there will be higher-than-average
peak growth in 2011-2012, as the recovery
takes off, peak growth can be expected
to stabilize around 1.4%-1.5% in 2014-15.
Compared to what IOUs were forecasting
before the crisis, we see a system peak
drop of 30 GW in 2011and we anticipate
that drop to persist through 2015 when it
may still be around 25 GW.
LOWER WHOLESALE GENERATION PRICES
AND ASSET VALUATIONS
Decreased oil, gas and coal commodity
prices will result in lower wholesale
power prices in all organized power pool
markets. Given the correlation that exists
between natural gas prices and power
(energy) prices in most regions of the
United States, near-term pressure on gas
prices will also affect profits from coal
and/or nuclear merchant plants. In addition,
a slowing economy and energy efficiency
also threaten to reduce power
demand growth below levels we might have
previously looked for.
Compared to their 2008 levels, expected
prices for 2009 will drop by 15-40%
depending on the type of power, baseload,
around the clock (ATC) or peaking. On
average, the drop is about 25-20%.
Longer term, wholesale power prices
will recover over a 2-3 year period as commodity
prices increase again and power
demand recovers. Prices for 2010 may
recover somewhat (say, by 5%) but it will
not be until 2011 that prices will get back to
their 2007 level and they may not recover
their 2008 level until 2013 at best. So, for
the next 5 years, the industry will basically
experience deflated prices; the average
price through 2013 is estimated at 85% of
2008 prices. Past 2013, prices will be
impacted by Federal carbon policy if a new
GHG bill has been passed.
These wholesale price trends imply
lower merchant asset values with a drop on
average of 35-40% over last year (mid-2008).
Coal plants using Eastern coal may show
the worst drop, followed by load-following
gas-fired units and then nuclear and wind.
These fuel-specific asset changes will
impact over half of the IPP asset base,
including the larger players, even those
with hedged and relatively well diversified
asset portfolios. This has been reflected in
the recent stock price drops of several publicly-
owned IPPs. Many IPPs will have to deleverage and sell assets; some of the top
10-15 IPPs may actually be bought out. This
will result in some industry consolidation
and possibly as much as 30-40 GW of secondary
market transactions in the next two
years.
REDUCED PLANT ADDITIONS
When we factor all these efforts, we
see delays of two years or more in the need
for new plants. In many regions, the need
year (i.e., when new plants are needed to maintain the proper reserve margin in that
area) has been pushed back to 2015-2017.
Given the amount of current backlog that is
still expected to proceed (some with
delays) in spite of the crisis, only a few
regions really need plant additions by 2014.
This means that IPPs will not have much
project development work to carry out for a
while.
We estimate plant additions to drop
by 35 GW between 2009 and 2015, compared
to what was planned in the summer
of 2008 before the crisis hit. The biggest
impact is on fossil plant additions: 12 GW
less for new coal capacity and 26 GW less
in new gas plants for a total of $55 billion in
reduced capital commitments over the next
seven years. The only bright spot is that
renewable plant additions will do better
thanks to the new tax incentives and
monies provided under the Obama administration.
We now project total capacity additions
in the US power sector of roughly 80-
85 GW through 2015 – including 18 GW
(21%) of coal; 28 GW (33%) of gas; and 38
GW (46%) of wind. About 30-35 GW
remains in development play, mostly in
wind projects.
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Furthermore, the bulk of new IPP
additions being in wind, much of the new IPP development activity will involve a new
crowd of players. This will be a big change
for traditional IPPs that mostly focused on
gas or, for some brave ones, coal plant
development. Many IPPs – including the
largest publicly-owned IPPs - will put on ice
most of their greenfield opportunities or
focus on “backyard project development”
by expanding or repowering their own
plants or focusing on a few regions rather
than trying to expand nationwide.
PROSPECTS FOR WIND
Renewable energy – including wind,
biomass and solar – will do better. IOUs
and IPPs are chasing all three and there are
already over 80 GW of projects under consideration.
In the following, we focus on
wind.
About 8.4 GW of new wind plants
came on line in 2008; this brought the total
amount of wind capacity in operation at the
end of 2008 at 25 GW. Wind provided 35%
of power plant additions in both 2007 and
2008 so it has become a major energy
source.
There is another 4.5 GW under construction
most likely to come on line in 2009-2010 and the current wind project
backlog is huge, up to 74 GW consisting of
over 400 projects. This mpressive backlog
is also the result of 2-3 years of very active
development pursued by over 100 companies
that were counting on the continuation
of a strong tax incentives and significant
participation from a growing number of
financial investors. If we extrapolate the
industry’s project development track record
to date, only a third of the backlog capacity
will get built – that’s still 25 GW. However,
we also need to look at the market drivers
and constraints that are likely to impact the
wind project development activity over the
next 5-7 years.
On one hand, we have a very strong
policy support for wind. The 2009 Stimulus
bill (ARRA) provides developers with a
choice between three tax incentives for projects
developed through 2012: a $21/MWh
production tax credit (PTC); or a 30%
investment tax credit or a cash grant in lieu
of an ITC. So, wind project developers now
have access to a broader range of incentives
which can now be tapped for a longer period, until the end of 2012. This 3-year 3-
incentive environment provides more visibility
than the industry has been able to
plan on in the past 5 years.
Another possible positive development
for wind would be the passage of a
Federal RPS standard in the next 12-18
months followed by the possible implementation
of a new cap-and-trade greenhouse
gas (GHG) regime that could be in place in
2013-2015 and would further foster the
development of wind projects. A Federal
20%-25% RPS could create a 20 GW or so
boost by 2015 in demand compared to a
state-mandated-RPS only scenario. That
boost would not materialize over night but
would be noticeable by 2013-14 and developers
may choose to anticipate it by 1-2
years. If they do, that means a resurgence
of development activity by 2011. However,
opposition to an RPS will be strong; furthermore,
there is a growing probability that
the Federal RPS be rolled into a new GHG
law.
The implementation of a cap-and-trade
GHG regime would further boost the
demand for renewables for the post-2015
period. Carbon prices in the $15-30/ton
range, quite possible for the 2015-2020 period,
could in theory imply an extra $5-
10/MWh bonus for wind projects. However,
once a cap-and-trade system is in place,
some if not all of the tax incentives that
have been made available for wind would
supposedly lapse. It is difficult to estimate
how this will affect prevailing wind prices in
2012-2105 when that mixed transition to
Federal RPS and then to cap-and-trade is
likely to take place, but it is reasonable to
assume that wind prices could benefit from
a $5-10/MWh boost for a while.
On the other hand, there are four market constraints that will affect future
wind project development prospects:
• How efficiently can developers use
available tax incentives
• An expected softness in negotiable
wind prices for the next 2-3 years
• Delays in RPS requirements due to
crisis-induced reductions in
electricity demand
• The need for new transmission
investments to enable the
development of more wind
resources.
Given the crisis and the low level of
profits that are being made, both PTCs and
ITCs have limited value to project developers.
Worse, these developers now cannot
find many financial institutions to whom to
sell these tax credits; the number of such
institutions has dropped from over 20 in
2007-2008 to less than 4 in the past five
months and their funding appetite has
dropped from $4 billion to half that at best.
This is now a one-year problem and it may
take 3 years for the situation to turn
around. In that context, the cash grant
incentive looks the best but it is a new incentive for which DOE needs to define
the rules and that may mean some delays.
Meanwhile, power prices for wind will
suffer the way wholesale power prices will,
so there will be further softness in the next
two years. Furthermore, a weaker power
demand will delay the timing and size of
many utilities’ RPS requirements by possibly
as much as 25 billion kWh in 2015; this
in turn would reduce by 7.5 GW the
amount of wind required by then – or the
equivalent of roughly 1 GW/year over the next seven years.
Finally, many wind projects cannot
proceed unless more transmission lines are
built. This is not a new issue and many utilities
have proposed new lines. However, the
track record for approving new lines is iffy.
In addition, there are competing demands
for capital since there are over a dozen
high-priority transmission expansion projects
(requiring over $15 billion of investments)
already under consideration under
DOE’s National Transmission Corridor initiatives (NIETC) launched in 2005. How
that affects the prospects for the other 30
potential transmission projects that could
spur the development of another 40-50 GW
of wind resources remains to be seen, especially
since these wind-related projects
could require over $25 billion of investments.
Together, that means $40 billion of
spending for an industry that was already
maxed out when it invested about $7-8 billion
in transmission per year in 2007 and
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