Taking Gas Liquids TO MARKET

Natural gas output in the U.S. has been rising steadily, thanks to the rapid development of North America’s vast shale basins during the past five years. And where natural gas is— usually—there are accompanying natural gas liquids (NGLs).

That’s because many of the most productive shale plays produce very wet, or NGL heavy, natural gas. The ethane, propane, butane and natural gasoline (pentane and heavier hydrocarbons) must be removed before the remaining dry methane stream goes into transmission lines and on to local distribution companies to fire hot water tanks, furnaces, hot tubs and kitchen stoves.

NGLs typically bring producers a premium price compared to the methane. So with natural gas prices at historic lows, shale plays with abundant NGLs—such as the Eagle Ford, Marcellus and Utica among others—currently draw greater driller interest than plays with dry-gas reserves, such as the Barnett and Haynesville.

The result? NGLs represent a growing slice of the total U.S. hydrocarbon production pie. Gas liquids extracted from gas processing plants made up around 12% of total U.S. liquid hydrocarbon production in 2011, according to the most-recent Energy Information Administration (EIA) numbers, and it projects that percentage will continue to grow.

The law of supply and demand works here, too. Abundant NGL supply means lower gas and NGL prices, hurting producers. But numerous industry observers say the potential impact of those low feedstock costs will be very beneficial to the economy—rippling through hundreds of products.

That NGL abundance has brought the predictable impact on prices. A U.S. Capital Advisors study early this year noted the biggest midstream story of 2012 “was the collapse of NGL prices, driven by extended petchem (plant) downtime, warm weather and growing supply.” The report forecasts modest improvement this year, projecting “ethane will trade at or slightly below a methane-equivalent price, with both gas prices and propane prices serving as governors on ethane prices.”

All of the barrel

The study adds to “watch the heavy end of the barrel closely” this year as increasing Eagle Ford NGL output “may pressure natural gasoline, but also create an incentive to export more refined condensate.”

So what could be the end result? The investor publication Barron’s recently featured a cover story headlined “The Next Boom” that discussed at length how gas and gas liquids, coupled with comparatively attractive labor and infrastructure costs, could bring the U.S. back to something akin to its manufacturing glory days of the 1950s.

A PricewaterhouseCoopers report released late last year, “Shale gas: Reshaping the U.S. chemicals industry,” discusses the impact of rising natural gas and NGL production on the nation’s chemicals business. The report projects that by 2025, the U.S. manufacturing industry could employ an additional 1 million workers and “lower their raw materials and energy costs by as much as $11.6 billion annually” as a result.

“Subsequently, [industry] may be able to take advantage of low-cost chemicals to create plastic-based substitutes for other materials, such as metal, glass, wood, leather and textiles.” The trend “could provide a strong economic incentive for U.S. manufacturers to reverse offshoring of manufacturing activity and build production facilities in the United States,” it adds.

The U.S. Capital Advisors study listed several what’s hot/what’s not issues currently facing the midstream. Among the hot issues it identified are growing propane exports, short ethane demand in the near term, homes for gas condensate on the heavy end of the NGL barrel and, in a related issue, liquefied natural gas (LNG) exports.

“Not” issues include LNG imports, dry-gas plays and ethane prices.

Total U.S. NGL supply, including gas processing and refinery output, was more than 3.3 million barrels (bbl.) per day in the second half of 2012, an increase of more than 7% from the 2011 period. Field production from gas processing plants represents more than 70% of that number.

The EIA estimates first-quarter 2013 NGL field production will average 2.44 million bbl. per day, some 2.5% above the first three months of last year. For all of 2013, the federal agency forecasts production to average 2.45 million bbl. per day, rising to 2.47 million bbl. per day in 2014.

The agency adds that gas-liquid consumption increased during 2012 despite the unusually warm 2011- 2012 winter, primarily because growing supply created lower prices and increased demand—particularly by the petrochemical industry.

NGL oversupply

Wells Fargo Securities projected in late 2012 that the domestic NGL market would be oversupplied by 64,000 bbl. per day for the year and oversupplied by 86,000 bbl. per day in 2013, based on its assumptions for ethane rejection into natural gas pipeline streams.

Midstream’s investment in new infrastructure to move all those gas liquids—as well as growing natural gas and crude oil production—runs into the tens of billions. Recent industry estimates predict a significant uptick in pipeline construction in 2013, even in comparison to a very active 2012.

One of the larger midstream projects focused on gas liquids—in particular ethane—is the Appalachia to Texas, or ATEX, Express Pipeline, which owner Enterprise Products Partners LP projects will enter service in the first half of 2014. The 1,230-mile system will have an initial capacity of 190,000 bbl. per day and will link Marcellus and Utica producers with the NGL hub at Mont Belvieu, Texas, outside Houston.

Jim Teague, vice president and chief operating officer at Enterprise, pointed out in a recent presentation that ATEX will have a link to every petrochemical plant along the Gulf Coast via Mont Belvieu. That could be crucial for its success since the region has the largest concentration of petrochemical operations in the world.

Growing NGL production from the liquids-rich unconventional plays has had another impact on the nation’s NGL supply—the mix of NGLs available. The shales typically produce lighter hydrocarbons so the percentage of ethane and propane has been growing.

EIA and Wells Fargo numbers show the total ethane cut for 2012 was above 40%. In 2003—before development of the shale plays took off—ethane made up 36% of the average NGL barrel. On the heavy end, the percentage of natural gasoline fell to 13% from 19% in 2003.

But where will the NGLs go? The supply side of the equation has changed. Now the demand side must adjust.

Four key factors

David Deckelbaum, senior exploration and production analyst with KeyBanc Capital Markets, told attendees at the recent Hart Energy Marcellus-Utica Midstream conference in Pittsburgh there are four factors that impact the future of NGLs:

• More than half of NGL demand comes from the petrochemical industry, using mostly ethane and propane to produce products such as ethylene.
• Heavier NGLs (butane and natural gasoline) are more transportation-driven and will likely remain tied to crudeoil pricing.
• Remaining demand beyond the petrochemical industry comes from domestic heating and exports—primarily for propane.
• Propane, butane and isobutane have the greatest export potential.

North American petrochemical firms have taken note of ethane’s bargain price and responded accordingly with plans to build new steam cracker plants—or reopen closed plants. Cracking plants convert NGLs into the ethylene feedstock fundamental to a vast array of thermoplastic resins, including multiple grades of polyethylene that go into thousands of products.

But the whole NGL barrel is key to making other resins, including polypropylene, polystyrene and butadiene.

Wells Fargo projects “ethane demand could increase by an incremental 148,000 bbl. per day as a result of heavy-to-light conversions, 78,000 bbl. per day from ethylene capacity expansions/debottlenecking, and 317,000 bbl. per day from construction of fine, new world-scale crackers. Ethane is now the lowest-cost ethylene feedstock, in addition to being the cheapest and easiest to process.

“In total, we forecast U.S. Gulf Coast ethane demand could increase by 543,000 bbl. per day over the next seven years,” the Wells Fargo report found. It adds the ratio of light-gas liquids in the overall steam cracker feedstock slate had increased to 87.7% percent.

But ethane doesn’t enjoy a big world market and most overseas petrochemical plants use crude oil-based naphtha or heavier gas liquids as feedstocks. Thus a major barrier for potential customers comes in the millions of dollars needed to retool the plants to handle a different feedstock.

Ethane is a primary concern now for domestic petrochemical operators, Becca Followill, senior managing director at U.S. Capital Advisors, tells Midstream Business. “Roughly 97% of ethane is used in the petrochemical business. So fundamentally, all of that ethane is going to be used in the petrochemical business, or it's got to be exported—and exporting is tough.”

Still, ethane exports can and do occur. Most notably are the two Mariner projects under construction to serve Marcellus and Utica producers. Mariner East, a pipeline, processing and terminal project, will move an ethane-propane mix to a terminal at Marcus Hook, Pennsylvania. Ethane will be fractionated there for loading in tankers for shipment, primarily to Europe. The propane will go to domestic markets on the East Coast and to export.

Mariner projects

Range Resources Corp. joined with Sunoco Logistics Partners LP on Mariner East. Mariner East has a 15-year sales agreement with Swiss-based INEOS Europe AG for deliveries starting in 2015. INEOS recently ordered a new tanker from a Danish shipyard to transport the Mariner ethane to its plant in Norway. Contracted sales volumes will start at 10,000 bbl. per day in the first half of 2015 and increase over time to 20,000 bbl. per day.

In the opposite direction, Sunoco Logistics, MarkWest and other players are involved in Mariner West, which will move ethane to NOVA Chemicals’ petrochemical complex in Sarnia, Ontario, which has retooled to use ethane instead of naphtha. Sales of 5,000 bbl. per day are scheduled to start this year, rising to 15,000 bbl. per day.

But the big ethane market will be here at home. The EIA says planned expansions at several ethylene plants in 2013 will lead to increases in expected NGL consumption of 40,000 bbl. per day in 2013 and 30,000 bbl. per day in 2014. And multiple forecasts see demand rising still further in 2015 and beyond.

Long term, expanding domestic ethylene capacity will have an enormous impact on the nation’s petrochemical industry, Teague added. He pointed to several large, recently announced ethylene plant projects along the Gulf Coast, including world-scale ethylene plants proposed by such firms as ExxonMobil, ChevronPhillips Chemical and Formosa Plastics. Sasol, the big South African refiner and petrochemical firm, has announced plans for a new cracking plant at Lake Charles, Louisiana. All would be world-scale plants—a capacity to manufacture 2 billion pounds per year, or more, of ethylene.

“When these plants come on, our ethylene industry will be able to produce well in excess of 70 billion pounds per year of ethylene. And every (existing) ethylene plant is making investments to use more ethane,” Teague said.

There are plans for new ethylene capacity outside the Gulf Coast. Shell is in the planning stages for an ethylene cracker outside Pittsburgh and other, smaller ethylene crackers are on the drawing board in Appalachia and along the Gulf Coast.

A recent Barclays Research report at the end of 2012 counted 16 ethylene plants “in various stages of development at this time.” Smaller ethylene plants are possible, too, since regional plants serving regional plastics consumers may not need to match the bulk of the large-scale Gulf operations, according to Jim Cutler, chief executive at Appalachian Resins. He told the recent Marcellus-Utica Midstream conference “not all ethylene plants have to be world scale,” and added the petrochemical industry needs to adopt “a new petrochemical business model that recognizes the shale-gas sea change.”

The feedstock of choice

Cutler described Appalachian Resins as a start-up that wants to develop a 500 million-pound-per year integrated ethylene/polyethylene production facility in the Northeast. The company views itself as a regional producer, he said. But regardless, “ethane has become the feedstock of choice” in the business.

So how much of the domestic gas liquids production will all these expansions consume? Teague noted that 70 billion pounds per year of ethylene equates to 3 million bbl. per day of gas liquids or 12 billion cubic feet per day of natural gas.

He provided numbers that show how the U.S. and its ethane-based petrochemical industry has moved from being the world’s high-cost ethylene provider in 2005, at around 40¢ per pound, to the low-cost provider at the end of 2012 at less than 15¢ per pound.

Meanwhile, feedstock costs for naphtha-based feedstock used at most overseas ethylene plants have climbed substantially along with the price of crude oil.

The American Chemistry Council estimates more than 50 new chemical projects valued at more than $40 billion have been announced to date. By 2017, the total investment will exceed $64 billion, it adds. Rising gas and gas liquids production “is one of the most exciting domestic energy developments of the past 50 years” the petrochemical trade group said in a 2012 report, calling the trend “a game changer” for the industry, “creating a competitive advantage for U.S. manufacturers, leading to greater investment and industry growth.” The report sees a $72 billion investment coming in eight key industries: paper, chemicals other than pharmaceuticals, plastics and rubber products, glass, iron and steel, aluminum, foundries and metal fabrication.

“These investments will engender $121 billion in additional industry output by these eight manufacturing industries, roughly a 7.3% gain above what output would be otherwise in the 2015-2020 period,” the report said.

“We've seen expansions happening already, but the big thing has got to be new crackers coming online, and those are mostly in the 2016-2017 timeframe,” Followill at U.S. Capital says.

Starting again

Dow Chemical restarted ethylene production at its mothballed, 3.3 billion pounds-per-year St. Charles plant at Hahnville, Louisiana, in December 2012. It shuttered the plant in January 2009.

In an announcement, Dow hailed the opening as a first step in a “comprehensive investment plan to further connect U.S. operations with cost-advantaged feedstocks from increasing supplies of U.S. shale gas and deliver a long-term competitive advantage for Dow’s downstream businesses.”

The firm added it plans to increase ethylene and propylene supply and ethane cracking capabilities at existing U.S. Gulf Coast plants to “strengthen the competitiveness of Dow’s Performance Plastics, Performance Products and Advanced Materials businesses and enable profitable growth in the Americas.”

There are multiple other, NGL-based projects in the works. Enterprise Products has announced plans for one of the world’s largest propane dehydrogenation (PDH) units on the Texas Gulf Coast that will require 35,000 bbl. per day of propane to produce 1.65 billion pounds per year of polymer-grade propylene. Operations could start in the second half of 2015.

And all that dry gas won’t be left behind by the chemicals business. Low gas prices are resurrecting the U.S. ammonia and urea industries. A Barclays Research report issued at year-end 2012 found “four ammonia facilities are slated either to restart or to under expansion, in total adding approximately 70 million cubic feet per day to natural gas consumption as feedstock,” as well as expansion of domestic methanol manufacture. Further afield, steelmakers have developed a new process called direct-reduced iron “that significantly expands the use of natural gas as feedstock in the metals industry” in place of metallurgical coal. And Hart Energy’s FUEL magazine, a sister publication of Midstream Business, recently featured an article on the expanding use by domestic refiners of natural gas for hydrocracking and hydrotreating, “effectively gas-to-liquids projects” that treat heavy vacuum gasoils left over from other refining processes to create distillates, including diesel and jet fuel.

Petrochemicals aren’t the only market for NGLs, and midstream operators are moving ahead to meet other customer demands. The proposed Unity Pipeline promises to create a larger market for condensate and light oil as diluents for Canada’s large production of heavy oil sands crude when it enters service by January 2015, Steve Jacobs, president of Harvest Pipeline Co., tells Midstream Business.

“Overall, this system will provide Utica and Marcellus producers with additional markets for lighter production,” he says. “For our Canadian brethren, this will be a new diluent supply from a new basin.” Initial capacity would be 60,000 bbl. per day when service starts in early 2015 with a potential for expansion to 120,000 bbl. per day.

Unity will connect with Enbridge’s Southern Lights Pipeline, and also could serve Kinder Morgan’s Cochin Pipeline