Renewable Energy: Coping with Variability Part 1: Supply Management

Dec 21, 2006 Roger Arnold, energypulse.net

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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