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Petrochemicals: Shale reopens the tap on US production

11:38 AM MDT | March 19, 2013 | —Clay Boswell

Shale gas development has granted the US chemical industry a renewed lease on life by driving costs down, pushing margins up, and attracting a flood of capital investment.

Just five years ago, the US chemical industry’s best days were clearly in the past. Reports of its demise were, however, greatly exaggerated. Surging domestic production of natural gas from shale deposits has restored the US chemical industry’s cost advantage, spurring a flood of capital investment that is expected to exceed $100 billion through 2030, according to IHS Chemical estimates.

Thomson: Nova shifts Corrunna feed to NGLs.
Lashier: CPChem Texas cracker on track for 2017.

“There has probably been no greater turnaround for a market,” says John Stekla, director/ethylene studies at IHS Chemical. He recalls the common wisdom five years ago when he joined the firm. “My first speech to a conference was basically an obituary for the North American petrochemical business,” he says. “And the calls I’d get from the financial community—they were asking what plants would be next to shut down, and they focused on tiny differences in competitiveness. For the last four years, however, it’s been nothing but birth announcements.”

The transformation has been particularly striking in ethylene, where producers have switched en masse from cracking oil-based feedstock naphtha and imported condensates to natural gas–derived ethane from the United States, in the process reducing their costs to some of the lowest in the world. LyondellBasell Industries says that as recently as 2009, imported condensates accounted for more than half of the feedstock used at its US ethylene plants. By the end of this year, it will have the capability to use domestic natural gas liquids (NGLs) and domestic condensates for 100% of feedstock needs.

Ethylene production capacity, on the wane for the last decade, is growing again. Some ethylene plants are emerging from hibernation.

In December 2010, for example, Eastman Chemical restarted one of two idled crackers at its Longview, TX, facility. “Eastman took actions early on to benefit from the shale gas boom,” says Ray Ratheal, director/energy and climate change policy, feedstock and energy procurement at Eastman. Earlier this year, Eastman announced that it was discussing options for the other idled cracker at Longview with several potential partners. “While it is difficult to predict timing, one common theme as we’ve been in discussions with third parties is an interest in getting something done the first half of this year—an interest we share,” Ratheal says.

Dow Chemical recently restarted a 380,000-m.t./year cracker in St. Charles, LA, that had been idle for 4 years.

Ethylene plants are also being expanded. Westlake recently completed a 105,000-m.t./year expansion at its Lake Charles, LA, facility. Williams and Ineos each plan expansions in 2013, while LyondellBasell, and Westlake will be expanding in 2014-15.

Nova Chemical is converting its Corunna, ON, cracker and may expand it, says Grant Thomson, president, olefins and feedstock at Nova. “We are in construction of an approximately $250-million conversion of the cracker to allow it to utilize up to 100% NGLs, primarily ethane from Marcellus. We are also investigating a possible expansion of the cracker to support a new proprietary technology polyethylene (PE) facility in the region.”

The greatest surprise has been the number of new grassroots ethylene plants now in the works. Between 2016 and 2018, a period of only three years, eight new grassroots crackers may come onstream.

“We are redirecting much of our major growth capital toward the US,” says Mark Lashier, executive v.p./olefins and polyolefins at Chevron Phillips Chemical (CPChem). CPChem announced plans to build an ethane cracker and derivatives facilities on the Texas Gulf Coast in March 2011. “We are on track to build a world-scale 1.5 million m.t./year ethane cracker and 2 PE units along the US Gulf Coast as part of our USGC Petrochemicals Project,” Lashier says. “If approved later this year, expected start-up is 2017.”

CPChem is also pursuing several related projects, Lashier notes. At its Cedar Bayou Chemical Complex, in Baytown, TX, the company is building a 250,000 m.t./year on-purpose 1-hexene plant, the world’s largest, which will completed next year. CPChem expects to complete a 19% expansion of NGL fractionation capacity at its Sweeny plant in Old Ocean, TX, in May. The company is also studying the possibility of expanding normal alpha olefins capacity by 20%, a project that would be completed by the end of 2015 if approved.

The mother of invention

The US chemical industry built its global dominance on some of the lowest natural gas prices in the world. Cheap gas meant cheap energy, cheap feedstocks, and comfortable margins. As the twentieth century came to a close, however, the nation’s recoverable energy reserves began to dry up, and US producers lost their competitive advantage. Gas prices rose, plants shut down, and investment went to regions with better economics, such as the Mideast.

Most observers saw inevitable decline, but a few recognized an opportunity to innovate. Although rising natural gas prices undermined the economics of chemical production, they improved the economics of two new drilling technologies that have since changed the very definition of recoverable: horizontal drilling and hydraulic fracturing.

The use of fracking and horizontal drilling to access shale gas gained momentum once the use of chemical additives to improve throughput was introduced in 1998. Over the next decade, the technology proved itself and, by 2008, it had influenced even the most authoritative estimate of recoverable natural gas reserves, the biennial assessment of the Potential Gas Committee. In 2000, the committee estimated recoverable gas reserves in the lower 48 states at 587 trillion cu ft (Tcf). The number varied little over the next 4 years, increasing to 597 Tcf in 2002 and 607 Tcf in 2004—but a distinct shift occurred in 2006, when the estimate leaped to 700 Tcf. In 2008, the estimate shot to 1,299 Tcf; and over the next 2 years, it continued to gain speed, soaring to 1,898 Tcf in 2010—triple the estimate from just 6 years earlier. The 2012 estimate is expected to be published next month.

The increase stems almost entirely from the influence of fracking on recoverability, says Ron Gist, senior principal analyst at IHS Energy Insight. “It’s not like we’re finding new reserves,” he notes. “It’s more that we’re finding out how to recover it.”

The shale advantage

Shale gas has had an immediate impact on the US gas market. Whereas gross annual withdrawals of natural gas from gas wells, oil wells, and coal-bed wells consistently totaled close to 24 million cu ft/year between 1994 and 2006, the sum began to rise in 2007, and it has continued to grow (graph, p. 18). Withdrawals from conventional gas wells have actually declined, but supply from shale has exceeded the shortfall by an expanding margin since 2008, so that by 2012, withdrawals from all sources totaled 30 million cu ft/year—an increase of 25% over the pre-shale norm.

In most of the world, natural gas prices are closely tied to the price of crude oil, even indexed against it. Until recently, the same was true in the United States, but the linkage has dissolved amid the rising flood of shale gas. The change was obscured by the recession of 2008, but it became evident in 2009: US oil prices, boosted by economic recovery, began to rise, but natural gas prices, suppressed by the growing supply glut, did not. The two have decoupled, and as long as the gap between them remains or grows, so will the potential advantage to US chemical producers that rely on natural gas for energy and feedstocks.

For US ethylene producers, the shale advantage is huge. Before the decoupling, ethylene margins were about 4 cts/lb, or breakeven, at the bottom of the cycle, but production costs have become much more favorable, Stekla says. “We forecast that the bottom margin in the next trough will be about 19 cts/lb on ethylene cash costs, and long term, about 15 cts/lb,” he says.

The crop of ethane crackers coming onstream between 2016 and 2018 will enjoy even better margins, Stekla notes. “In the period between 2017 and 2025, we forecast that the US cash cost of production off ethane is going to be $810/m.t.,” he says. “Over that same period, Southeast Asia is forecast to be $1,281/m.t. So we’re projecting that the cash cost advantage over that period, once all these projects get built, will be $470/m.t.—which is 21.3 cts/lb. And, in my opinion, it’s fairly conservative when it comes to the ethane pricing.” The advantage today is even greater, he adds—closer to $1,000/m.t.

Beyond ethylene

The shale advantage extends beyond ethylene. For example, the United States was the global leader in methanol output until rising gas prices in the country and better economics abroad quickly drove production away, forcing the United States to import 90% of its methanol requirements, according to estimates by IHS Chemical. Shale has brought the cost of feedstock methane back down, and methanol production has returned. Producers are restarting plants idled over a decade ago, relocating plants from other regions, and building entirely new plants.

In 2011, Methanex restarted a 470,000-m.t./year plant in Medicine Hat, AB, that had been idled since 2001. The company is also relocating a 1 million-m.t./year plant from Chile to Louisiana, with start-up expected in 2014. Orascom Construction Industries (OCI; Egypt) restarted a 750,000-m.t./year plant in Beaumont, TX, that had been idle since 2004, when it was owned by Terra Industries. And LyondellBasell plans to restart a 780,000-m.t./year plant in Channelview, TX, later this year.

New plants in the works include Celanese’s plan to bring online a 1.3-million m.t./year plant in Clear Lake, TX, in 2015. Earlier this month, South Louisiana Methanol (SLM), a partnership of Zero Emission Energy Plants (ZEEP; Austin, TX) and Todd (Wellington, New Zealand) announced plans to build a $1.3-billion facility in St. James Parish, LA.

“Domestic demand for methanol in North America is just under 7 million m.t./year currently, with a growth rate of 2.1% expected over the next 5 years,” notes Marc Laughlin, associate director/Americas at IHS Chemical. “If you add the viable projects, the ones we think are actually going to happen, then total domestic production capacity will be well over 6 million m.t./year by 2017, and if you add SLM, it’s more like 8 million m.t. Therefore, the capacity we’re adding will be greater than the anticipated domestic demand.”

Other methanol plants are being planned as components of fuel projects. G2X, for example, has announced plans to build a world-scale methanol plant as part of a $1.3-billion, natural gas–to-gasoline facility in Lake Charles. Sasol has begun front-end engineering and design for a 96,000-bbl/day gas-to-liquids facility in Lake Charles, and the company is considering another in Canada.

Cheap methane has also drawn fertilizer production back to the United States.

In February, CF Industries said it would proceed with a $3.8-billion plan to expand ammonia, urea, and urea ammonium nitrate (UAN) plants in Donaldsonville, LA; and Port Neal, IA. Last year, OCI announced plans for a $1.4-billion ammonia, urea, and UAN complex at Wever, IA; and Mosaic said it was considering the construction of a $700-million ammonia plant in Faustina, LA. In December, Agrium said it was finalizing the location for a nitrogen fertilizers plant in the Midwest.

Shale complications

North America’s shale advantage has not come without trade-offs. Switching crackers to ethane feed means switching them off of naphtha, with the result that the coproducts propylene, butenes, and aromatics are no longer produced. The result has been shortages in some coproducts, and rising prices. However, the same conditions that gave rise to the problem also provide the basis for at least part of its solution – on-purpose production. For just as shale gas has increased domestic supplies of ethane, it has also increased supplies of propane and butane, and proven technologies are available for converting each to its olefin analog.

Propylene has received the greater attention, and the technology of choice has been propane dehydrogenation (PDH). Petrologistics, the first mover, brought online a 658,000-m.t./year PDH facility in Houston in late 2010. Several others are on the way.

Dow Chemical plans to build 2 PDH units, a 750,000-m.t./year unit that will start up in 2015 and another that may start up in 2018. Enterprise plans a 750,000-m.t./year PDH unit on the Texas Gulf Coast that will start up in 2015, and the company says it is considering a second. Formosa Plastics has announced a 600,000-m.t./year PDH unit, scheduled to start up in 2016, as part of a $1.7-billion project set at Point Comfort, TX. Williams plans to install a roughly 500,000-m.t./year PDH unit in Alberta. In February, Ascend Performance Materials announced that it would begin construction of a $1.2-billion PDH facility at Alvin, TX, in January 2014, with start-up planned for late 2015.

Only one on-purpose butadiene project is underway so far. TPC Group, which currently produces butadiene by extraction, has announced plans to renovate an idled 270,000-m.t./year butane dehydrogenation unit at its Houston site, with start-up expected in 2016.

Risky business?

US chemical producers have seen their fortunes improve at such speed that the transformation seems somehow suspect, as if it might be reversed just as quickly, but analysts at IHS Chemical see little cause for fear. The shale advantage will extend far into the future, they say. Although estimates of recoverable natural gas reserves change every year, they only go up.

“Everybody pretty much believes that we’re just scratching the surface here in the US,” Gist says. “They keep finding new resources and [new ways to get at them]. In fact, we were having a conversation a year or so ago with a group of people. We said, ‘The low-hanging fruit has already been developed.’ And the guy replies, ‘Yeah, but we’re finding new trees all the time.’ And that’s really what it amounts to. The US is not going to run out of oil and gas reserves in the foreseeable future. Whether it is 20 years or 100, I don’t know—but there’s an enormous amount of resource out there.”

Applications to allow exports of liquefied natural gas have also prompted fears that the shale advantage might be squandered on the global gas market. The controversy has divided the chemical industry, with companies such as ExxonMobil counseling against excessive regulation of trade, while companies such as Dow and Huntsman argue for a cautious, incremental approach.

“We believe that the markets should determine how and where natural gas is used,” says Nova Chemical’s Thomson. “A healthy natural gas production market will result in a healthy petrochemical market.”

CPChem’s Lashier says the company supports free market principles for exports. “Our greater interests are best served when all involved in the value chain enjoy sustainable margins, leading to continued investment along the entire chain,” he notes. “The most sustainable value chain would support investment-grade margins to every participant, including those manufacturers downstream from chemicals.”

Kevin Kolevar, v.p./government affairs and public policy at Dow, says the company does not oppose free trade. “The issue though is really what happens in the midterm range, in the neighborhood of 2019–20,” he explains. “We are afraid that you could have a convergence of several significant sources of demand hit at about the same time.”

One source of demand will be increasing industrial use in the manufacturing sector. “That’s obviously good,” Kolevar says. More worrisome is increasing consumption from the electric power sector. Low prices may push coal aside, but the greater risk is that increasingly stringent EPA regulations will undermine coal’s viability in electric power generation. “That frankly is a real concern, and that could have a significant impact upon domestic gas consumption,” he says.

Finally, increased exports would also cut into domestic availability. The issue would be particularly acute in 2019–20, when a number of export facilities are scheduled to go online, says Kolevar.

“We are concerned that you could have a real domestic supply crunch,” he explains. “That would reintroduce volatility into the price of gas and gas liquids in this country and stifle what we see as the beginning of a manufacturing renaissance in the country.”













 
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