Power Hungry (21 page)

In areas where wind turbines have been added to the electric grid, utilities and electric grid operators must have plenty of natural-gas-fired power generation available that can be switched on quickly when the wind stops blowing. Assuring that generation capacity is always available requires major investments in gas wells, gas pipelines, and gas storage fields to be certain that there's enough gas available for generators. And all of that infrastructure costs money, which means that consumers will ultimately have higher electric bills due to wind power.

Gas analysts and utility companies are still grappling with all of the ramifications of the variability of wind power. In the United States, gas-fired power plants operate about 36 percent of the time.
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(The utilization rate, or capacity factor, for coal plants, which provide baseload, or always-on, power, is usually 70 percent or more. Many nuclear plants operate at about 90 percent.) But the addition of new wind-power resources may mean that those gas-fired generators are used even less, meaning their capacity factor may decline to just 25 percent or maybe 30 percent. And by reducing the amount of time those generators and other parts of the infrastructure get utilized, wind power reduces the capital efficiency of the equipment, which raises the effective cost of that equipment. Put another way, the relative inefficiency of wind as a power source requires traditional electricity producers to invest more capital in expensive hardware—such as gas-fired generators, gas storage equipment,
and other items—that may be used less often than they would be in the absence of wind power.

The concept is fairly simple to understand. Let's assume that ABC Utility is required to install 100 megawatts of wind turbines. To assure that those turbines are able to provide reliable quantities of electricity, ABC must also install 100 megawatts of gas turbines. (As stated in earlier chapters, every megawatt of wind power that is added to a given electricity system must be backed up with a megawatt of gas-fired generation.) Let's further assume that the cost of those 100 megawatts of gas generation is $100 million.

Without the wind mandates, ABC could operate those gas turbines at a capacity factor of 36 percent or more. In doing so, it could calculate a certain return on its $100 million investment. But as the wind turbines are added to ABC's grid, they reduce the gas turbines' utilization rate and make them less efficient from a capital standpoint. And somehow, somewhere, consumers will have to pay for that inefficiency.

This problem was discussed in a July 2009 report by Pöyry, a Helsinki-based consulting firm. In an analysis of how the variability of wind power will affect the British and Irish electricity markets, Pöyry concluded that new power plants designated to back up wind power “will have to operate at low, and highly uncertain loads, and under the current market arrangements the likely returns [on capital] do not appear good.” The report goes on to say that revenues from any backup generation “will be volatile and uncertain to the point where a plant may only operate for a few hours one year, and then some hundreds the next. Generating companies will need to factor this possibility into their investment strategies.”
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The Pöyry conclusions are nearly identical to those made by the International Energy Agency. In its “Natural Gas Market Review 2009,” the agency said that as renewable capacity is added, “gas-fired capacity will increase while its overall load factor may be reduced.... This switching will have an impact on the profitability of new investments.”
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The agency used Spain as an example of the need for gas-fired generation and the variability of wind. “Peak summer loads coincide with periods when there usually isn't much wind, while the opposite happens during winter, meaning large differences in terms of gas-fired plant load: on 20
June 2008, Spain broke a record in terms of peak daily gas demand from the power sector.”

On that day in June 2008, Spain's gas-fired generators were operating at a capacity factor of 75 percent. But six months later, on December 20, when the wind was blowing strongly, the capacity factor for the country's gas-fired generators was just 18 percent. “Such fluctuations require heavy investments in gas storage, particularly of the type needed to respond quickly to large gas demand movements from power generators,” said the IEA.
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Though it is true that gas consumption declines during periods when the wind is providing lots of electricity, it's not yet clear how large those savings will be. Nor is it clear that the savings in fuel costs will be enough to offset the capital costs incurred to install the needed gas storage capacity, pipelines, and generators. Furthermore, all of that gas- and power-delivery infrastructure—and the generators, in particular—must be staffed continually. The utilities cannot send workers home only when the wind is blowing. The generators must be available and staffed to meet demand 24/7.

The additional costs imposed by wind power can be seen by looking again at Colorado, one of the states in the vanguard of the push for renewable energy. In 2004, Colorado voters approved a ballot measure requiring the utilities in the state to generate or purchase enough renewable energy to supply at least 10 percent of their retail electricity sales. Since that time, the state's legislature has raised that target to 20 percent of retail electricity sales, and that target must be met no later than 2020.
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In December 2008, Xcel Energy, a natural gas and electric utility that serves customers in eight states, issued a report on the costs associated with integrating wind power into its mix of generation assets in Colorado.
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The study says that the utility expects “the costs of integration to be predominantly fuel costs resulting from 1) the inefficiency of generation due to wind generation uncertainty,” and “2) the cost of additional gas storage.”
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To be clear, the integration of wind power into a specific electricity grid will vary widely depending on the size of the grid, what types of fuels it uses, and the amount of wind being added. But Xcel is correct about the need for gas storage. The gas-fired generators needed to back up
wind power must be switched on or off several times per day, and underground gas storage facilities must be located relatively close to the generators so that there is enough pressure in the gas pipeline to keep the generators going. For parts of the United States that have favorable geology—consider western states such as Colorado, Texas, Oklahoma, and Kansas, where gas production is common—the gas storage issue may not pose a problem. But in other states, and particularly in other countries with less-favorable geology, the lack of gas storage may pose a real barrier to wind power.

Sources
: EIA, American Coalition for Clean Coal Electricity, “Your State” (clickable map),
http://www.cleancoalusa.org/docs/state/
. Data current as of July 2009.

Despite the situation in Colorado, there have been no comprehensive studies, on either the federal level or the state level, exploring how increasing deployment of wind power will affect natural gas infrastructure and demand. Furthermore, the dynamics of the wind–natural gas relationship will vary widely. It will likely be particularly problematic in the states that are heavily dependent on coal-fired power plants for their electricity. If states such as Wyoming and West Virginia—which are 94 percent and 97 percent reliant on coal, respectively—are required to add renewable electricity to their grids, those states will likely have to make large parallel investments in new gas generation and gas-delivery infrastructure.

The reason those states will need to add gas infrastructure is that coal plants are not designed to be turned on and off. Instead, they are designed to run at a constant rate. When they run below their optimum
design rates, they become less efficient, and they may emit more carbon dioxide and air pollutants at lower power output levels than when they operate at maximum output.

All of this matters because Americans have been repeatedly told that electricity generated from wind costs less than electricity produced by other forms of power generation. That's only true if you don't count the investments that must be made in other power-delivery infrastructure that assures that the lights don't go out.

The extreme variability of wind generation means that wind turbines are simply a supernumerary—an extra—element of our electricity generation system. They don't displace existing power plants at all. Instead, when they are added they must be carefully integrated into the electricity grid—and backed up with gas-fired generators—so that they won't cause too much disruption. And therein lies the punch line: The costs of all the new gas-related infrastructure that must be installed in order to accommodate increased use of wind power should be included in calculations about the costs of adding renewable sources of energy to the U.S. electricity grid. Those calculations should be done on a state-by-state basis. But so far, little, if any, of that type of work has been done.

So why hasn't it been done? Part of the blame should be aimed at promoters like Pickens, who have continually understated the costs of moving the U.S. toward wind power. In addition, Pickens confuses the issues of wind-generated electricity and oil by claiming that more wind power would mean less oil use and therefore less need for imports.

That claim leads to the next myth-busting opportunity. Americans have repeatedly been told that increasing the production of “green” energy in the United States will result in a reduction in U.S. imports. That's just not true. Nearly all of the wind turbines now being produced depend on a rare element called neodymium. One of the most confounding aspects of the push for “green” energy in America is that, by rushing headlong into efforts to reduce the use of hydrocarbons, the United States is making itself even more beholden to China, which has a stranglehold on the world's supply of neodymium and other “green” elements.

Going “Green” Will Reduce Imports of Strategic Commodities and Create “Green” Jobs

F
OR DECADES, THE MOST important invention attributed to Baron Carl Auer von Welsbach was the flint used in cigarette lighters. In the world of inventions, that bit of acclaim is notable, though it doesn't necessarily rise to the level of world-changing. Nevertheless, the work that von Welsbach—a Viennese chemist born in 1858—did on the flint (an alloy made of 70 percent cerium and 30 percent iron) was part of his ongoing interest in a group of elements known as the lanthanides.
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And his predilection for the lanthanides led him to discover two cornerstones of the “green” economy: neodymium and praseodymium.

Those two materials, along with the other elements found in the lanthanides' row of the periodic table, are essential commodities in nearly all of the technologies that are seen as solutions to our energy challenges, from wind turbines and hybrid cars to solar panels, computers, and batteries. Why are they so important? The lanthanides—which are also called “rare earths”—have special features at the quantum mechanics level. The configuration of their electrons allows them to have unique magnetic interactions with other elements.

These characteristics make the lanthanides a key chokepoint in the development of the “green” economy. And that leads to one of the biggest myths about going green: the notion that if only we would use more hybrid cars, wind turbines, solar panels, and other such devices, we would be free of messy international entanglements and the need to import oil and other strategic commodities. But here's the reality: China has a de facto monopoly on the global trade in the lanthanides, and about 90 percent of the world's lithium, an essential element in high-capacity batteries, comes from just three countries: Argentina, Chile, and China.
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Huge lithium deposits exist in Bolivia, but that country's populist leader, Evo Morales, has made it clear that he won't be selling it on the cheap.
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In its headlong rush to go “green,” the United States may simply be trading reliance on one type of import for reliance on another. Instead of requiring oil supplied by dozens of producers located in the Persian Gulf and elsewhere, it will need rare earth commodities produced by the Chinese as well as lithium mined by a handful of foreign countries.

Of course, we live in a global economy, particularly when it comes to energy. The petrostates of the Persian Gulf and elsewhere must sell their oil. They can't drink it or use it to water their geraniums. The same holds true for the countries that produce lithium and the lanthanides. And given the ongoing globalization of the world economy, it stands to reason that the marketplace will help to assure that buyers and sellers will reach agreed-upon prices for whatever goods or services are on offer. That said, the difference between the hyper-global oil sector and the rare earths business is akin to the difference between aluminum and dysprosium.
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The global oil market allows price discovery for crude oil and a myriad of oil commodities on a near-instantaneous basis, and that market is fully integrated with a large network of buyers and sellers. For instance, in 2007, the United States imported oil or oil products from ninety different countries.
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In 2008, twenty-one nations were each producing more than 1 million barrels of oil per day.
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If one producer's price is too high, buyers can almost certainly find another seller.