Renewables XIII – One of Wind’s Hidden Costs

In earlier articles we looked at wind power, what it costs, what it does to the grid, and what to do when the wind is not blowing.

Now a frequent comment – which conceals more than it reveals – is: “the wind always blows somewhere”. This is true – if you have lots of wind farms that are geographically dispersed you do average out your peaks and troughs, and you do also reduce the % change hour by hour.

However, if you have 20% of your average power coming from wind, then on one given day it might be 60% of your requirements, yet the next day it might be 0.3%. This means that sometimes you are “winding back” your conventional generation, and sometimes you are “cranking up” your conventional generation – and much more in absolute terms than in a network of 98%+ conventional generation. The larger the penetration of wind energy the more problems this causes.

The question has come up a few times without being answered – what is the impact on efficiency of conventional power generation?

It’s clear that the impact depends on the penetration of wind. Very recent analysis is hard to find.

First, here is an older NREL study from 2004:

It is important to understand that the key issue is not whether a system with a significant amount of wind capacity can be operated reliably, but rather to what extent the system operating costs are increased by the variability of the wind..

..Over the past two years, several investigations of these questions have been conducted by or on behalf of U.S. electric utilities. These studies addressed utility systems with different generating resource mixes and employed different analytical approaches. In aggregate, this work provides illuminating insights into the issue of wind’s impacts on overall electric system operating costs.

I extracted two useful examples from the NREL study:

PacifiCorp:

PacifiCorp, a large utility in the northwestern United States, operates a system with a peak load of 8,300 MW that is expected to grow to 10,000 MW over the next decade. PacifiCorp recently completed an Integrated Resource Plan (IRP) that identified 1,400 MW (14%) of wind capacity over the next 10 years as part of the least-cost resource portfolio.

A number of studies were performed to estimate the cost of wind integration on its system. The costs were categorized as incremental reserve or imbalance costs. Incremental reserves included the cost associated with installation of additional operating reserves to maintain system reliability at higher levels of wind penetration, recognizing the incremental variability in system load imposed by the variability of wind plant output.

Imbalance costs captured the incremental operating costs associated with different amounts of wind energy compared to the case without any wind energy.

At wind penetration levels of 2,000 MW (20%) on the PacifiCorp system, the average integration costs were $5.50/MWh, consisting of an incremental reserve component of $2.50 and an imbalance cost of $3.00. The cost of additional regulating reserve was not considered. These costs are considered by PacifiCorp to be a reasonable approximation to the costs of integrating the wind capacity.

Great River Energy:

Great River Energy (GRE) is a Generation and Transmission electric cooperative serving parts of Minnesota and northeast Wisconsin. It is primarily a thermal system in the Mid- Continent Area Power Pool (MAPP) region with a summer peak load in excess of 2300 MW, growing at 3%-4% per year.. As part of its planning process to meet this objective, GRE performed a study with Electrotek that examined adding 500 MW of wind in 100 MW increments between now and 2015. GRE operates with a fixed fleet of generation and uses a static scheduling process, so it did not decompose the problem into the three time periods commonly used in the analysis of ancillary-service costs in larger utilities. It also looked at providing the ancillary services required from its own resources, including a 600-MW combined-cycle unit, which was subsequently cancelled. GRE found ancillary- service costs of $3.19/MWh at 4.3% penetration and $4.53/MWh at 16.6% penetration. It is likely that the costs would have been higher without the combined-cycle unit and self-providing the ancillary services without economical intermediate resources.

It appears that these studies are based on nameplate values (I didn’t find an explicit statement but the wording implies it and later references to the data agree). That’s a pretty big difference, because in GRE’s case it means that the “16.6%” would actually be something like “5-6% of average electricity production from wind”. The 16.6% would be when the wind farms were operating at their maximum.

It seems like there should be many more studies, especially given the increase in wind penetration of electricity networks in Germany, UK and Ireland. However, many references work their way back to the same papers. For example, Overview of wind power intermittency impacts on power systems, MH Albadi & EF El-Saadany, Electric Power Systems Research (2010) says:

Smith et al. reported that the existing case studies have explored wind capacity penetrations of up to 20–30% of system peak and have found that the primary considerations are economic, not physical [9].

The reference [9] is Utility Wind Integration and Operating Impact State of the Art, J Smith et al, IEEE Transactions on Power Systems (2007), which states:

On the cost side, at wind penetrations of up to 20% of system peak demand, it has been found that system operating cost increases arising from wind variability and uncertainty amounted to about 10% or less of the wholesale value of the wind energy [2]. This finding will need to be reexamined as the results of higher-wind-penetration studies—in the range of 25% to 30% of peak balancing-area load—become available. However, achieving such penetrations is likely to require one or two decades.

The reference [2] here is Wind plant integration, E DeMeo et al, IEEE Power Energy Mag (2005) which has the same data as the NREL study, not surprising as two of the authors are the same.

Albadi & EF El-Saadany 2010 compile some data, note the reference again is to peak penetration:

Figure 1

We can see a big range. For example:

the UK costs at the top of the graph, with peak penetration of 20-40% (=average penetration of 6-12%) having costs of around $5/MWh, or 0.5c/kWh
the Finland costs at the bottom right with 32-65% (=average of 10-20%, but I’m unsure of their capacity factor) having costs of around $1/MWh, or 0.1c/kWh

The study that produced these particular values (and some others) is H. Holttinen et al 2009. This is from 2009 and what appears to be the same data is in a paper in Wind Energy (2011). However, the studies that produced their data: Finland and Nordic – PhD by Holtinnen 2004; Sweden – paper by U Axelsson et al from 2005; Ireland – 2004 study; UK – paper by Strbac et al from 2007; Germany – Dena Grid study from 2005; Minnesota – paper for Minnesota Public Utilities Commission from 2006; and California – paper by Porter et al from 2007.

Holtinnen et al 2011 summary:

From the cost estimates presented in the investigated studies it follows that at wind penetrations of up to 20 % of gross demand (energy), system operating cost increases arising from wind variability and uncertainty amounted to about 1–4 €/MWh of wind power produced (Fig. 5). This is 10 % or less of the wholesale value of the wind energy. The actual impact of adding wind generation in different balancing areas can vary depending on local factors. Important factors identified to reduce integration costs are aggregating wind plant output over large geographical regions, larger balancing areas, and utilizing shorter gate closure times with accurate forecast systems and sub-hourly schedule changes.

An important point, often missed by pundits looking at Denmark:

The interconnection capacity to neighbouring systems is often significant. For the balancing costs, it is then essential to note in the study setup whether the interconnection capacity can be used for balancing purposes or not. A general conclusion is that if interconnection capacity is allowed to be used also for balancing purposes, then the balancing costs are lower compared to the case where they are not allowed to be used.

The two points for Greennet Germany at the same wind penetration level reflect that balancing costs increase when neighbouring countries get more wind (the same applies for Greennet Denmark). For a small part of an interconnected system, a wind integration study stating a high penetration level can also be misleading if the wind penetration in neighbouring areas is low and interconnection capacity plays a major part in integration.

They have many interesting points in their paper:

In Denmark the TSO has estimated the impacts of increasing the wind penetration level from 20 % to 50 % (of gross demand) and concluded that further large scale integration of wind power calls for exploiting both, domestic flexibility and international power markets with measures on the market side, production side, transmission side and demand side ([19] and [20]).

This kind of implies there are big issues, but the documentation is locked away in conference proceedings. Surely some published papers have come out of this important question so I will continue to dig..

A digression, for people concerned that wind power research and costing ignores transmission costs, another (counter-) example:

Transmission cost is the extra cost in the transmission system when wind power is integrated. Either all extra costs are allocated to wind power, or only part of the extra costs are allocated to wind power – grid reinforcements and new transmission lines often benefit also other consumers or producers and can be used for many purposes, such as increase of reliability and/or increased trading. The cost of grid reinforcements due to wind power is therefore very dependent on where the wind power plants are located relative to load and on the grid infrastructure, and one must expect numbers to vary from country to country.

Grid reinforcement costs are by nature dependent on the existing grid. The costs vary with time and are dependent on when the generator is connected. After building some lines, often several generators can be connected before new reinforcement needs occur. After a certain time, new lines, substations or something else is needed.

The grid reinforcement costs are not continuous; there can be single very high cost reinforcements. Using higher voltages generally results in lower costs per MW transported but this also means that there are even higher increments of capacity and grid costs. The same wind power plant, connected at different times, may therefore lead to different grid reinforcement costs. For transmission planning, the most cost effective solution in cases that require considerable grid reinforcements would be to build the transmission network for the final planned amount of wind power in the network – instead of having to upgrade transmission lines in several phases.

Conclusion

It seems like everyone studying wind power believes the additional costs incurred as a result of having to ramp up and down conventional power systems are relatively low – typically less than 0.5c/KWh for 20% penetration. Likewise, everyone agrees that there is a real cost to be paid. The cost for 50% penetration is unclear, even if it is feasible.

There doesn’t seem to be any real world data for high wind penetrations, which is not surprising as Germany, a wind power leader, has only about 10% of (annual average) power coming from wind, and Denmark is effectively part of a much larger grid (by virtue of interconnection).

Whether or not the current estimates factor in the lifetime impact on power stations (due to lots more heating and cooling causing more stressing of various parts of the system) is something that might only be found by the real world experiment of doing it for a couple of decades.

[Note that many statements and press releases on the subject of wind do not clarify whether they are talking about “peak”, i.e., nameplate, or “average”, i.e. the nameplate x capacity factor – it is essential to clarify this before putting any weight on the claim].