Issue Date: September 21, 2009
Stepping On The Gas
As recently as a few years ago, North American petrochemical companies worried that high natural gas prices would put them at a disadvantage internationally. The result, they feared, would be gleaming new chemical complexes overseas and boarded-up plants back home.
Today, with rock-bottom natural gas prices that are low relative to crude oil, petrochemical makers are more hopeful. The prices might not lead to a resurgence of the U.S. as a petrochemical exporter, but they might help U.S. plants stay open. To some extent, the prices are a consequence of the deep recession. But companies also have the natural gas industry to thank for devising ways to tap into new resources.
About 70% of the ethylene capacity in North America is based on natural gas liquids—ethane, propane, and other hydrocarbons that are separated from natural gas’s main component, methane. For decades, until about 2000, natural gas in North America was cheaper, on an energy content basis, than oil. Other regions, namely Europe and Asia, have petrochemical industries based on oil-derived feedstocks such as naphtha. The disparity allowed the U.S. to export up to 15% of its output of polyethylene and other ethylene derivatives.
By the early part of this decade, however, natural gas supplies couldn’t grow fast enough to meet demand from the power and industrial sectors, and gas prices spiked to levels that made it more costly than oil. The U.S. saw periods in which “heavy” oil-based feedstocks held the advantage over “light” gas-derived ones. The U.S. lost its advantage over oil-based petrochemical plants overseas and at the same time saw the Middle East assume the export mantle with its own cheap gas.
In March 2004, Gary K. Adams, president of Houston-based consulting firm Chemical Market Associates Inc. (CMAI), told attendees at the firm’s annual conference that high natural gas prices would induce more supplies, eventually causing gas to “retreat to levels slightly below crude oil parity.” But he added, “There is no plausible scenario at this time that returns gas values, versus those of crude oil, to the very attractive levels of the past, barring a very significant and lasting geopolitical event.”
Five years later, natural gas did return to such levels. Today it is around $3.00 per million Btu, which, on an energy-equivalent basis, is $17.40 per barrel of oil, whereas oil itself is trading above $70 per bbl. “We’re hitting ratios that I’m not sure we have ever seen before,” says Grant Thomson, president of olefins and feedstocks at Nova Chemicals, which operates massive ethane-based crackers in Alberta.
Andrew Swanson, vice president of chemicals for the consulting firm Nexant, says the low natural gas prices have opened export markets for U.S. chemical suppliers. “This has really been driving the chemical industry in the U.S. these past six months,” he says, noting that some polyethylene producers have been able to export as much as 30% of their output.
But today’s prices don’t prove CMAI’s Adams wrong. If the housing crash and subsequent financial crisis doesn’t qualify as a “significant and lasting geopolitical event,” then nothing does. Indeed, the recession has exacted a toll on natural gas demand, which in the first half of 2009 declined by 4.4% versus the same period in 2008. “In North America, one part of what has been driving these low gas prices has been a decline in demand,” Thomson says.
Another factor, though, is the growing supply of natural gas being extracted from shale found deep under the ground. These deposits may hold the key to the future competitiveness of the North American chemical industry. The Barnett shale in northeast Texas, the Haynesville shale in Louisiana, and the Marcellus Formation that begins in western New York and extends south beneath the Appalachian Mountains are just some of the deposits that offer massive potential.
It has been known for more than a century that the shale is rich in gas, but geologic realities had put this gas out of reach. Joseph H. Frantz Jr. is chief executive officer of gas exploration company Unbridled Energy, which is developing shale in New York, Ohio, and Canada. He says the shale is less permeable than even concrete. “If you looked at it, you would wonder how you would ever get any gas out of it,” he says.
The breakthrough, Frantz says, was to combine two technologies that were well known to the oil and gas industry: horizontal drilling and hydraulic fracturing. In a traditional vertical well, contact between the well and the rock is limited due to the shale formation’s vertical shallowness, which can be measured in hundreds of feet. But because the shale extends horizontally for miles, horizontal drilling exposes the well to more of the gas-containing rock.
In hydraulic fracturing, gas companies pump water down the well at high pressure, up to 8,000 psi, creating cracks in the rock that extend as far as 3,000 feet from the well. A sand-based additive known as a proppant holds the cracks open and allows the natural gas to seep out.
In a presentation before the Federal Energy Regulatory Commission (FERC) last November, Terrence L. Ruder, president of marketing and midstream production at Devon Energy, an early pioneer in the Barnett shale, profiled shale’s potential. He said some 6 billion to 8 billion cu ft per day of gas comes from shale in the U.S., enough to meet up to 12% of U.S. demand. Ruder projected that the shale will supply 25% of gas needs by 2018.
Observers expect shale to have a lasting impact on North American gas supplies. According to an assessment released in June by the Potential Gas Committee, a nonprofit organization affiliated with the Colorado School of Mines, the U.S. natural gas resource base is 1,836 trillion cu ft, a 39% increase over the estimate of just two years prior. At present rates of consumption, such a resource will keep the U.S. supplied for another 80 years.
But all this gas isn’t much of a benefit to the chemical industry unless it contains feedstocks such as ethane. “More gas is always good,” Thompson says. “But what’s really good is more gas with liquids in it.”
The amount of ethane in the shale depends on the formation. The Barnett shale is relatively rich in heavier components. In fact, Devon operates a gas-processing plant in Bridgeport, Texas, that can extract 57,000 bbl of natural gas liquids per day.
But petrochemical makers acknowledge that market forces will push prices higher. Nova’s Thomson prefers a sustainable advantage to a short-term windfall anyway. “Because we are a big buyer, obviously we enjoy low prices,” he says. “But we also want prices for natural gas to be significant enough that they also provide an incentive for drilling, which, longer term, keeps feedstocks flowing to us.”
Indeed, because of the low prices, gas suppliers have recently cut back on drilling new wells. According to oil-field services firm Baker Hughes, the North American rig count—a measure of how many gas wells prospectors are drilling—stood at 700 at the end of last month, a decrease of 56% versus a year ago.
The prices are putting a damper on some of the shale activity as well. Ruder told FERC that the shale gas industry needs prices between $6.00 and $9.00 per million Btu to develop new fields.
But even if the natural gas market equilibrates higher, petrochemical makers still expect that gas will be cheaper than oil. “North America is going to be advantaged against everywhere in the world except for the Middle East,” Thomson says.
Recent corporate moves indicate that chemical company executives are betting natural gas will retain an advantage over oil for a long while. Historically, LyondellBasell Industries was an outlier among North American petrochemical makers. It cracked about 70% heavy, oil-based feedstocks and 30% light, natural-gas-based raw materials. Now the company is running 25% heavy and 75% light, according to Vaughn Deasy, its senior vice president of base chemicals and polyethylene.
He says LyondellBasell was able to make the shift because of its ability to run lighter feedstocks through existing assets. “We think we have the most flexible system of olefins crackers in the world,” Deasy says.
But some big modifications were required as well. The company closed its heavy-cracking Chocolate Bayou, Texas, plant earlier this year.
In addition, the company had to idle parts of plants that handle the coproducts made when heavier feedstocks are cracked. As part of a project to enable its Corpus Christi, Texas, plant to use lighter feedstocks, LyondellBasell is shutting down butadiene extraction and toluene hydrodealkylation units.
In 2006, Nova completed a project in Corunna, Ontario, aimed at improving the site’s feedstock flexibility and increasing its output of ethylene. Dow Chemical has made investments in a cracker in Louisiana so it can accept lighter feedstocks.
However, Brian Ames, global business director for olefins, aromatics, and aromatic derivatives at Dow, views the export boom as temporary. “While the current export conditions have been significant, competitiveness with Middle East exports to Asia is problematic, especially over the next few years as new capacity is absorbed,” he says. “The U.S. will be very competitive for supplying the domestic market, but even at these gas prices, it is hard to compete with the Middle East.”
Dow is in the process of shutting plants to, in Ames’s words, “right size” its portfolio to correspond to U.S. demand. It is closing 1.6 million metric tons’ worth of ethylene derivatives capacity on the Gulf Coast in a program that will see it shutter polyethylene, styrene, vinyl chloride, and other plants. Ames says the project will improve Dow’s ethylene economics in North America because it will no longer have to buy 1.3 million metric tons of ethylene each year.
The company is also closing its smallest ethylene unit, a cracker in Hahnville, La., that uses a mostly ethane feedstock. “We are not shutting it down because we don’t think it is competitive,” Ames says. “We are shutting it down because we don’t have the need for the ethylene.”
Low natural gas prices will keep such closures to a minimum, Nexant’s Swanson maintains. “I think there will be no more closures, or at least fewer closures than might have been the case if gas had stayed up at $6.00 to $10 per million Btu,” he says. “I don’t think it will lead to a sudden rash of investment, but it will help the longevity of people still in the business.”
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