Bam! Royal Dutch Shell Plc alone answered in early June at least half of Marcellus wet-gas producers’ questions about how to get their premium ethane to market. The super-major, which bought Marcellus producer East Resources Inc. last year as its entry to the world-class Appalachian unconventional-gas play, will use the ethane right there in the midst of the play.

Shell plans to build an ethane cracker—in West Virginia or Pennsylvania, as the states are vying for the jobs and an estimated $1-billion-plus capital investment—that would start making 2.2 billion pounds of ethylene per year by 2015.

The plant is expected to use some 60,000 to 80,000 barrels (bbl.) of ethane per day as feedstock. Meanwhile, the Marcellus might be producing more than 120,000 bbl. per day by 2015, according to analysts at Tudor, Pickering, Holt & Co. Inc. of Houston. Based on that figure, ultimate export volumes could be cut in half, they note.

By “export” they’re referring to the Gulf Coast or Sarnia, Ontario—or even to petrochemical plants outside North America. While the Shell plan represents a firm buyer of a good deal of oncoming ethane supply from the wet-gas window of the Marcellus play, there’s still another half to get to market.

Three plans are in the works.

As crude-oil prices increase, the profit from gas-liquids-rich plays improves. However, the price of the dry gas or methane is unchanged. Meanwhile, profit from gas-liquids-rich plays improves as dry-gas prices improve, as well, meaning the liquids are a bonus no matter the oil- or gas-price market.

Ethane economics

Ethane for which there is no means of getting to market can be left in the gas stream, depending upon pipeline operators’ approval, and sold to customers as extra-Btu natural gas. In most cases, the producer doesn’t get paid as much for it as it would if the ethane were stripped out.

But Range Resources Corp., the Fort Worth-based producer that pioneered the Marcellus play in 2007, aims to get paid for it. And, it’s a bundle: In recent years, ethane has been priced at an average of 46% that of the Nymex price for crude oil, on a million-Btu basis. Simple methane or dry gas is about 9% of that. Thus, U.S. gas producers describe having liquids in their mix these days like this: Even 25% of the price of West Texas Intermediate crude, for gas liquids, is worth more than 100% of the Nymex price for dry gas.

“At the end of the day, we'll get gas-plus for the ethane, which is something that we never thought would happen two years ago.” — John Pinkerton, chairman and chief executive, Range Resources Corp.

Range Resources, which is estimated to have one of the largest wet-gas exposures in the Marcellus, is working on two firm-purchase deals with ethane consumers—The Dow Chemical Co. on the Gulf Coast and Nova Chemicals Corp. in Sarnia, Ontario—to further boost its rate of return from the play.

It’s no small amount of natural gas liquids (NGLs) that Range expects to make, either. For example, in the liquids-rich window of Range’s leasehold, the smallest-completion-type (that is, eight fracture stages on a 2,500-foot lateral) well will make about 5 billion cubic feet equivalent (Bcfe) of which 3.6 Bcf is dry gas or methane and 239,000 bbl. are NGLs. A 3,500-foot lateral and 12 frac stages could produce as much as 6.7 Bcfe or 4.1 Bcf of methane and 425,000 bbl. of liquids.

“Maybe we can turn that into 500,000 bbl. per well,” says Jeff Ventura, Range Resource’s president and chief operating officer. “Given the huge acreage position we have on the liquids-rich portion of the play, this could be very impactful.”

Across its leasehold, the company estimates it could potentially produce some 307- to 463 million bbl. of liquids with the small completion scheme. “I would expect the performance could continue to climb with time as we get better and better about what we're doing. So it's not unreasonable to think we'll reach the high end, with 463 million bbl. of liquids,” Ventura says.

But, the potential for revenue uplift doesn’t stop there. Ventura’s calculation includes leaving the ethane mixed with the methane when put into pipe to market.

“On the one hand, the price of ethane has reacted to increased supply, but, because the price of crude oil has risen, the actual yield price for ethane has gone up.” — Bruce Vincent, president of Swift Energy Co.

“Once we start extracting ethane, it's going to double our liquid yields, so the 463 million bbl. become 926 million bbl. net to Range,” he says. “And, then, if we can get better about where we land (our wells) and how we drill and complete, really, you're approaching 1 billion bbl.”

Competing plans

A major push to monetize Marcellus ethane began with Range’s work on the play several years ago, says John Pinkerton, Range’s chairman and chief executive. Over time, the company has teamed with other wet-gas producers to leverage the combined supply power. The prospective buyers are impressed with the figures, he adds.

“This is going to be a lot of ethane. At the end of the day, we'll get gas-plus for the ethane, which is something that we never thought would happen two years ago. We were hoping it would, but, now, it's clearly going to happen. It will have a big impact on our realizations and our margins and, obviously, enhance the intrinsic rate of return,” says Pinkerton.

Range Resources and Denver-based midstream operator MarkWest Energy Partners LP (which is one of the largest gas processors and fractionators in Appalachia along with Dominion Resources Inc. and Caiman Energy LLC) have two plans for getting the ethane to markets upon users’ signatures on firm-purchase agreements.

In the first plan, the companies’ Mariner East project, some 50,000 bbl. of ethane per day would be piped to Philadelphia and loaded into pipeline-operator Sunoco Logistics Partners LP’s ships. Then, it can be sold into any market, including Dow Chemical Co.’s operations and to other users on the Gulf Coast or to buyers abroad.

In the second, the Mariner West project would allow about 65,000 bbl. per day to be put in an existing Sunoco Logistics pipeline, modified for ethane export, at Vanport, Pennsylvania, and sent to Pittsburgh-based Nova Chemicals’ plant at Sarnia, the old Lake Huron oil town that hosts a large petrochemical industry. According to the plan, Nova would convert its legendary Corunna olefins cracker there to 100% ethane. Beginning this summer, MarkWest estimates its additional fractionation capacity will be able to recover more than 40,000 bbl. per day of ethane from wet Marcellus output and, by mid-2012, 70,000 per day.

Competing with Range Resources-MarkWest schemes is an ethane-export plan calling for the conversion of Spectra Energy Corp.’s Texas Eastern Pipeline, in Pennsylvania and Ohio, and El Paso Corp.’s Tennessee Gas Pipeline system that runs from Ohio to the Gulf Coast.

Ethane sold for prices ranging from $4.22 to $21.02 during 2008 through 2010, at an average of $8.62, compared with methane or dry gas, which fetched an average of $5.55.

The assets would be repurposed into an ethane line called the Marcellus Ethane Pipeline System, or MEPS. It would move some 60,000 bbl. of ethane per day to Dow, ChevronPhillips and other petrochemical manufacturers whose announcements recently of expanding their ethane demand, primarily on the Gulf Coast, is encouraging, says Doug Foshee, El Paso chairman, president and chief executive.

“Others have estimated that this could result in an additional demand in the Gulf Coast of over 250,000 bbl. per day of ethane,” says Foshee. “We believe our MEPS project is best positioned, and we continue to work to get this one over the finish line.”

Spectra is a 50/50 partner with El Paso on MEPS, which is an $800-million to $1-billion project. Greg Ebel, Spectra’s president and chief executive, notes,“Right now, there is no good way to get the ethane from the Marcellus down to the Gulf Coast. So we see an advantage in some pipeline that's not being utilized, which El Paso brings to the table. The Gulf Coast is a 600- or 650-million bbl. per day market. And that's where we want to be taking the ethane.”

Also, MEPS is advantaged in that it is expandable by several hundred thousand bbl., he says. “Producers and consumers are weighing all of their options and it's very competitive. I like our position, because that expandability piece is going to be valuable. That expandability of the pipe is going to serve the Gulf Coast better than, say, a marine solution,” Ebel says.

Ethane sold at 46% the price of crude oil during the past two years, compared with natural gas or methane, which was priced at 9% that of West Texas Intermediate crude oil.

Getting off naphtha

Today, the big prize to the petrochemical industry is that natural-gas based ethane, as feedstock for chemical manufacturing, is far cheaper than crude-oil based naphtha. Andrew Liveris, Dow’s chairman, president and chief executive, says, “If you look at Asia and naphtha, they have become clearly the lowest-margin, highest-cost jurisdiction, with Europe being a close second.”

Range’s Pinkerton explains, “You have a global economy that's using naphtha. You have this huge push of ‘How do I get off naphtha and get to ethane?’ I think what you see is this global movement to the cheapest feedstock that you can. And you'll do all the ethane that you can.”

Once MarkWest’s oncoming, additional fractionation capacity is online, Range will also get 12% greater recovery of the propane that’s in its wet gas, upon extracting the ethane. “So it's a plus, plus, plus and the story continues to get better as you look at all the alternatives and as you have a global demand for this product,” says Pinkerton.

Dow, the world’s largest maker of plastics, calls procuring less expensive ethane as feedstock the company’s next catalyst in enhancing its profit performance. “The specialty-chemical company graveyard is littered with companies that didn't understand the strategic importance of integration,” Dow’s Liveris says.

Elsewhere, on the Gulf Coast, more ethane supply is coming from producers’ liquids-rich Eagle Ford production in South Texas. One such producer, Swift Energy Co. based in Houston, has operated in South Texas for more than 25 years and is putting Eagle Ford gas liquids into pipe to market.

Bruce Vincent, president of Swift Energy, says, “The price of ethane has gone up, although it’s gone down as a percentage of the price of crude. On the one hand, the price of ethane has reacted to increased supply, but, because the price of crude oil has risen, the actual yield price for ethane has gone up. At the end, it’s a benefit to the producer and to the user because they’re getting lower feedstock costs.”

South of the Eagle Ford area, Dow is planning to restart an existing ethane cracker and is increasing the feedstock flexibility of several others. Liveris says the restart will increase its U.S. ethylene-production capacity as much as 20% in a few years. “But we're not stopping there,” he says. “The arrangement with Range will give us access to the liquids from the Marcellus and complements the ethane- and propane-supply contracts that we already have in the Eagle Ford (in South Texas) and other shale-gas regions.”

Swift’s Vincent notes that new South Texas gas-liquids production has a fairly ready means of reaching Gulf Coast ethane users. Additional supply will be coming from the Midcontinent, as DCP Midstream LLC plans to convert ConocoPhillips’ Seaway refined-products pipeline to deliver 150,000 bbl. of NGLs per day, instead, to the Gulf Coast by mid-2013. In addition, Midcontinent operator Oneok Inc. has plans to expand its Midcontinent-to-Gulf NGL pipeline.

Dow, which has invested more than $500 million in feedstock flexibility on the Gulf Coast during the past few years, plans a new world-scale ethane cracker, similar to Shell’s, that it will fire up in 2017. It also plans a new, huge propylene plant at Freeport, Texas.

Liveris says, “We are already fully integrated in the propylene chain in all areas of the world with the exception of the U.S. Gulf Coast.” Once completed, Dow will only have to buy 10% of the propylene it uses in the U.S. “We currently buy 50% of our U.S. propylene. That's not sustainable,” he says.

New liquids-rich production from plays across the U.S. will make more than 200,000 extra barrels per day of ethane alone, not counting other NGLs, by next year. —Robert MacKenzie, managing director, energy and natural resources, FBR Capital Markets.

Getting it right

Meanwhile, by mid-2012, MarkWest's daily processing capacity in Appalachia will grow to nearly 1 Bcf. “This is pretty spectacular growth, when you consider that, in mid-2008, we did not have any asset in the Marcellus,” says Frank Semple, MarkWest chairman, president and chief executive. Semple believes the Appalachian NGLs-productive potential extends from the Huron/Berea shale in southeastern Kentucky to the Marcellus in southwestern Pennsylvania.

At its Houston, Pennsylvania, plant, MarkWest is charging up to produce 35,000 bbl. of propane and 25,000 bbl. of butane and natural gasoline per day. At that facility, it has 1.3 million bbl. of NGL storage capacity. “It's a very complex market out there right now for ethane. With the economics of ethane changing fairly rapidly, there's a lot at stake in getting it right,” says Semple.

Conversely, Rich Kinder, chairman and chief executive for Kinder Morgan Inc., is not jumping on the build-it-now bandwagon. The company already runs the 1,900-mile, 12-inch Cochin NGL pipeline from Alberta to near Sarnia, Ontario, and it is holding off building a new NGL pipeline out of Appalachia.

“We're not going to build a project of that size and capital cost unless we have long-term throughput commitments from shippers—either producers or aggregators in the Marcellus, or users up in Sarnia,” he says. “Until and unless we get those commitments, we're not going to build anything. We're still looking at the situation, but unless we get the contracts, we're not doing it.”

In addition to monetizing valuable Marcellus gas liquids, producers are anxious to get the product out of the gas stream that enters the pipelines. Producers know that shippers can reject gas that is too rich, or high in Btus.

Swift’s Vincent says, “What’s happening currently in the Marcellus is they are basically rejecting some of the NGLs in the processing, so it stays in the gas stream because they don’t have sufficient ability to get it to market. They’ll strip it out when they have sufficient markets to deliver it to and the economics justify it. They have to strip some out because the pipeline specifications require them to do that.”

The prize

For users that can capture the ethane, the prize is not small. Bill Herbert, managing director and co-head of research for Simmons & Co. International Inc., notes that integrated oil companies’ chemicals businesses reported record profits in the first quarter, posting a 40% increase in net income compared with first-quarter 2010.

“We believe U.S. Gulf Coast ethane-based crackers are among the most advantaged assets in the industry,” Herbert reports. The contribution is not insignificant in the largess of major oil companies’ earnings. For example, ExxonMobil Corp.’s chemicals unit contributed some 15% of operating income in 2010, he notes.

Vincent says, “What the industry has done in discovering this American treasure of natural gas has been a gift to American manufacturing and the American petrochemical industry. Their energy costs have been reduced by billions of dollars because of this increase in supply of natural gas and now natural gas liquids.”

In most gas-liquids streams, ethane is the most preponderant. Its dominance is a significant contributor to the sensitivity of ethane prices.

In fact, Robert MacKenzie, managing director, energy and natural resources for FBR Capital Markets, estimates that new liquids-rich production from plays across the U.S. will make more than 200,000 extra bbl. per day of ethane alone, not counting other NGLs, by next year.

Also, energy conglomerate Williams Cos. Inc. is interested in ethane as both a producer and user. The company operates a 1.35-billion-pound-per-year olefins cracker at Geismar, Louisiana, on the Mississippi River that also makes 90 million pounds of polymer-grade propylene. Its olefins division also runs 200 miles of ethane pipeline and a 500-million-pound-per-year propylene splitter.

Alan Armstrong, chief executive for Williams Cos., notes that more than 80% of petrochemicals manufactured in the U.S. use natural gas, while about 60% of olefins produced in the world are made from oil. "When you look at the cost advantage natural gas has over oil, you start to craft a picture of how advantaged the U.S. is because of low-cost gas."