One of the biggest issues with solar and wind power is their
variability. They produce power “when they want to”, and not
necessarily when we would like them to. There are ways to cope with
this variability, but each has some economic cost. In this
three-part article, we review current options, and suggest likely
developments for the near future.
Impact of Variability
Variability is an issue for both solar and wind, but it affects
the two sources differently. Since availability of solar correlates
reasonably well with periods of peak power demand, its impact is
usually taken to be positive. For that reason, we’ll set it aside
for now, and begin by looking at how variability affects the
economics of wind power.
Opponents argue that wind power never adds any generating
capacity to a regional power grid. The argument is that, because
wind is not reliable, the system must always have enough capacity in
other forms to meet its highest peak demand. Otherwise, it risks
rolling blackouts during calm periods with high demand. Hence, wind
power, when it is available, merely displaces other generating
capacity that must still exist. It conserves fuel and reduces CO2
emissions, but its “true” economic value is limited to the cost of
the fuel its operation displaces. For a coal-fired generating plant,
in the absence of a CO2 tax, that’s a meager 1.5 cents per
kilowatt-hour—not sufficient to justify the capital cost of wind
turbines under the usual financial models.
There is some validity to that argument. However, it mistakes the
nature of wind resources and the power grid. "Capacity" is not a
hard-edged number, and in any case the purpose of integrating wind
turbines into a system is not mainly to increase its maximum power
capacity rating. Its purpose is to reduce the consumption of fossil
fuels. Nonetheless, under the right conditions, the energy
contribution of wind resources can have utility well above the
marginal cost of fuel saved. Part of the trick to integrating wind
resources involves strategies that enable the “right conditions” to
apply more often.
There are just three basic mechanisms for coping with
variability. One is backing generation (supply management), another
is load management, and the third is energy storage.[1] In this
part, we’ll focus mainly on supply management. Later parts will look
more at load management and energy storage.
Load Balancing Today
Today, balancing is accomplished almost entirely via supply
management. Load management, in the form of “demand response”, is of
growing interest, but so far it has mostly been limited to emergency
curtailment of large loads during power crisis conditions.
The vehicle for load balancing is the grid within a “regional
balancing area”, or RBA. The typical RBA incorporates many
individual generating units of different types. They range from
advanced units with high capital cost but very low marginal cost for
energy generated (e.g., nuclear), to simple units whose marginal
operating costs are high, but which don't tie up much capital when
sitting idle. The former are preferred for meeting baseload demand,
while the latter are emergency backup units and "peakers". In
between are units whose marginal operating costs are reasonably low,
and whose designs allow them to be cycled on a daily basis without
undue stress. These units are started up or shut down as needed to
follow the daily load profile.
The ideal resource for load following is a hydroelectric plant. A
suitable plant has multiple hydro turbines and at least a small
receiving reservoir to buffer downstream river flow. Those features
allow its power output to vary widely, according to need. Its
long-term energy output is fixed by stream flow, but there is a lot
of flexibility as to when it is generated. That makes this type of
hydro a perfect complement for wind power. Power supplied by the
wind, when it is blowing, replaces water flow through the hydro
turbines. The water retained in the reservoir remains available to
supply power when the wind is not blowing. This is one of the
conditions in which the economic utility of energy from variable
wind resources is fully equal to that from regular power sources.
When a suitable hydro-electric plant is not available for
load-following, then coal-fired plants with multiple
turbine-generator units are the next best choice.[2] Typically,
groups of individual units share boilers and condensers. They are
usually scheduled to keep at least one of the units in a group
operating, so the boiler and condenser avoid stressful thermal
cycling.
Under normal circumstances, daily electrical demand is met
entirely using baseload and dispatchable intermediate units. If it
becomes necessary to draw on less efficient peakers and backup units
on a regular basis, then it's time for utility planners to start
thinking about adding more baseload and dispatchable intermediate
capacity—or promoting energy efficiency to reduce demand.
It's in this context that the economics of wind power must be
considered. Wind turbines have very low marginal operating costs.
When wind energy is available, it pays to use it. That can usually
be accommodated by juggling the schedule of start-ups and shut-downs
of existing intermediate units. The process is no different than
that used to meet variable demand over the course of a day. However,
it's less predictable a day in advance, which complicates life for
the transmission system operator (TSO).
Economics of Wind Energy Today
The industry consensus seems to be that in most RBAs, if the
level of wind penetration is below 20% of average demand, then the
variability can be accommodated without building new backing
capacity.[3] [4] Although the peak "in-feed" from a wind farm during
periods of high wind can be four times its average value, there is
usually enough intermediate capacity that can be temporarily shut
down to allow that level of in-feed to be accepted. Conversely, when
in-feed from wind resources is low, the level of intermediate
capacity that is already installed for following the daily load
profile will usually be sufficient to take up the slack for low wind
in-feed. Occasionally, during periods of unusually high demand and
low wind, it will be necessary to activate back-up units or invoke
demand response measures. That should be rare enough, however, as to
have only minor impact on operating costs.
On the other hand, the inability to predict, on a daily basis,
just when power from dispatchable load-following units will be
needed can have a major impact on expenses for a TSO. It may limit
the TSO’s ability to purchase low-priced power on long-term
contracts, and force it to turn more to the high-priced spot market.
That happened, for example, to NorthWest Energy in Montana when the
Judith Gap wind project came on line.[5]
When power must be purchased on the spot market, it’s usually
good news for the owners of dispatchable units, but bad news for
ratepayers. Even if the TSO is purchasing wind energy at rates that
are low compared to conventional sources, the higher priced spot
purchases can quickly offset any savings. As a result, the cost of
power to ratepayers goes up.
Strategies to mitigate the impact of spot market purchases exist.
They include long-term contracts formulated to allow more
flexibility to schedule power delivery on short notice, or
acquisition by the TSO of captive load-following resources that it
can draw on for short-notice scheduling around wind availability.
However, there is one effect that can’t be mitigated by any
supply-management strategy alone: an inherent reduction in average
capacity factor for the system’s dispatchable units.
The whole point of wind energy, after all, is to displace
generation that would otherwise be supplied by dispatchable
intermediate units and peakers. Fuel consumption and CO2 emissions
are reduced, but the units are still needed for meeting peak demand.
They simply operate with lower average capacity factors. That means
that the non-fuel portion of their power costs are amortized over
fewer kilowatt-hours delivered, raising the average cost of power.
There is a counter-effect by which wind helps to reduce the cost
of power to ratepayers. It’s a hard effect to quantify, however, and
not that easy even to explain. But I’ll try.
Consequences of Fuel Saving
In the case of paired hydroelectric and wind power, what gives
wind energy its high utility is that the “fuel supply” for
hydroelectric power—i.e., stream flow—is fixed. If more power is
needed, a hydroelectric utility can’t just go out and purchase more
stream flow. But every kilowatt-hour of energy that can be supplied
by wind is a kilowatt-hour of deferred hydro energy that can be
supplied later.
If the supply of fossil fuel available to generators within an
RBA were fixed by rationing (or perhaps by a carbon cap?) the same
situation would apply. The restricted fuel supply changes the system
from being power-limited to being energy-limited. Wind generation
and fossil-fueled generation then trade off in the same way they do
for wind and hydro power. The variability of the wind resource
becomes irrelevant, so long as it is paired with sufficient backing
generation.
At the present time, fuel supplies aren’t rigidly fixed. At
least, not at the level of an RBA. Yet something close to that
situation does exist at the national level. Supplies of natural gas
are tight, with very little elasticity. If the bid price rises, it
may prompt suppliers to sell gas from storage, but it doesn’t
directly lead to higher annual gas production. So a utility that
buys gas for power generation is ultimately buying it at auction
against other would-be gas users. To succeed, some other would-be
user must be priced out of the market.
In that situation, the reduction in fuel demand from use of wind
energy translates to a reduced market price for fuel. The wind
resource should technically be credited with the fuel price delta
for which it is responsible, applied across all fuel purchased. That
figure can be much larger than the direct cost of the fuel saved.
However, it’s diffuse, and can’t be measured directly. It can only
be estimated. What’s worse, it’s firmly enmeshed with that most
troublesome economic notion of “the common good”.
The major benefit of reduced fuel consumption for power
generation accrues not to those who paid for construction of the
wind resource, nor to the utility that purchases its output. Rather,
the benefit is to the community of fuel users as a whole, in the
form of lower fuel prices. But there is no way for the owners of a
wind resource or those purchasing its output to capture that
benefit; reduced fuel prices simply become their indirect “gift” to
the community. This is an example of why government subsidies can be
legitimate instruments of rational policy for the public benefit. As
much as free-market fundamentalists may rail against them, subsidies
can serve to motivate beneficial behavior that the market alone has
no means to reward.
At this point, those paying close attention will notice that I
have just argued, in effect, that construction of wind farms will
not significantly reduce total consumption of natural gas. It will,
instead, reduce the price of natural gas, and enable uses that would
otherwise have been priced out of the market to take up the slack.
Have I just undercut the entire green rationale for wind power?
Well, yes and no. Natural gas is still a much “greener” fuel than
coal, and it’s likely that most of the additional gas usage that
wind power will enable would otherwise be served by coal. Since coal
is not tightly supply-limited, the net effect should be a reduction
in coal usage. On the other hand, the lower fuel prices will reduce
incentives for efficiency improvements. Since efficiency
improvements are unquestionably the best long-term strategy we have
for reducing our “ecological footprint”, that would be bad.
The conclusion I would draw from that, however, is not the
paradoxical suggestion that wind power is actually an impediment to
reduced consumption of fossil fuels. My conclusion is much more
pedestrian: that the most effective policy for achieving reduced CO2
emissions will be to tax CO2 emissions, rather than subsidizing wind
power or other non-carbon energy sources. Surprise! The point goes
to the anti-subsidy free market crowd, after all.
Limitations of Supply Management
There are a number of important issues regarding supply
management that I did not discuss above. They include details about
the shape of the supply curve for wind farm output, and the
implications of long distance power transmission for supply
management. These are important issues, and those interested can
read more about them in some of the references given below. However,
the most important points to take from this discussion of supply
management can be summarized as follows:
- At low levels of wind penetration, the plot of daily demand
less wind farm output is qualitatively very similar to the plot of
daily demand alone. Any RBA that has dispatchable resources
sufficient to deal with the latter should also be able to deal
with the former.
- I.e., up to a certain level, variable wind power can be
integrated into the power supply system with no need to add new
balancing capacity. That level will depend on the particular
characteristics of a given RBA, but is generally considered to be
about 20% of average load.
- With wind shouldering a variable portion of the load, long
range forecasts of required supply from other sources become less
reliable. That can result in higher operating costs for the TSO if
it does not control its own generating resources. A smoothly
functioning hour-ahead market is needed to mitigate uncertainties
introduced by wind supply.
- At higher levels of wind penetration (e.g., those contemplated
for much of Europe) existing mechanisms for supply management
become insufficient. At that point, reliance on an exclusive
strategy of supply management becomes expensive, as added wind
capacity must be balanced by added balancing capacity.
A more efficient strategy for coping with variability at high
levels of wind penetration is to shift toward load management and
energy storage. “Load management”, in that case, does not mean
(only) load curtailment to reduce peak demand, but (more
importantly) time shifting of discretionary loads to match available
supply. We’ll look at that in some detail next week in part II.
Notes and References
[1] Long distance transmission could be considered a fourth basic
mechanism, but I prefer to view it as a way to extend the scope of
the other three mechanisms.
[2] Here “best” is meant from a technical and business economic
viewpoint; environmental considerations are another matter.
[3]
http://www.uwig.org/UWIGWindIntegration052006.pdf
[4]
http://www.ukerc.ac.uk/content/view/259/953
[5]
http://kirbymtn.blogspot.com/2006/06/wind-farm-requires-purchase-of-extra.html
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