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Repurposing assets usually involves some new infrastructure. A crew prepares to weld pipe during looping of the oft-reworked Seaway Pipeline. Photo courtesy of Enterprise Products Partners LP.
Singer and songwriter Peter Allen cer¬tainly didn’t have North America’s energy infrastructure in mind when he wrote his paean to renewed love, “Everything Old Is New Again.” But the lyrics apply.
The midstream buildout, which always fol¬lows the changing geography of oil and gas production, has included multiple projects to repurpose underused or misapplied assets. It’s hardly a novel concept—why build new when, say, that pipeline right over there pretty much matches the route you need and doesn’t see a lot of use nowadays? Meanwhile, greenfield projects prove increasingly difficult and expen¬sive as regulatory approvals, environmental worries, costs and public not-in-my-backyard opposition mount.
Pipelines generally lend themselves to such shifts, and the changes can be major. Crude oil lines morph into natural gas systems, flow directions flip—or a transmission pipeline becomes a header.
‘Lazy assets’
Repurposing can even take an asset out of the energy business. One of the more novel repurposing projects came along in the 1980s when The Williams Cos. Inc., which at the time owned a fiber-optic telecommunications unit, rejiggered several hundred miles of lightly used product pipelines in the Midwest to serve as conduits for new fiber-optic cables. That re-employed what Williams told investors were “lazy assets,” saved millions in right-of-way purchases, construction costs and no doubt some confrontations with recalcitrant farmers.
Another creative Williams repurposing proj¬ect in 2015 converted an empty airplane han¬gar at New York’s historic Floyd Bennett Field, part of the Gateway National Recreation Area, to a citygate linking a new Williams gas line to New York’s local distribution company. Since it involved U.S. National Park Service property, the project required a literal act of Congress for approval.
While repurposing of assets may be a fre¬quent strategy, the idea doesn’t always work, according to James P. Benson, a founding part¬ner of Dallas-based Energy Spectrum Capital. Midstream operators must determine what assets they have—and then what producer cus¬tomers need, he emphasized.
“There is a lot of repurposing of existing assets in the Permian, Scoop and other prolific areas. But in many cases, the need to develop new infrastructure exists as well,” Benson said. “With the technological advances in drilling and completion methods, most of the new wells are being produced at higher pressures and higher rates. In some cases, the existing infrastructure is not sufficient to handle the new activity, which means new pipe in the ground. There will always be a market for quality assets in these prolific areas.”
Overzealous repurposing can create some of the same problems as infrastructure overbuild, according to Matthew Lewis, director of equity research for East Daley Capital Advisors Inc.
“South Texas was pretty long natural gas pipelines, then they repurposed a lot of that pipeline to move NGL” as the Eagle Ford took flight, he said. “Now we’ve had a pretty sig¬nificant drop in drilling in the Eagle Ford, yet Mexico needs dry gas. But to move gas down into Mexico they would have to repurpose again—and that’s expensive. Companies that still have gas pipelines in South Texas have quite the advantage.
“It doesn’t do you any good if you’re repur¬posing pipelines back and forth every three to four years,” Lewis added. “And what happens if drilling picks up in the Eagle Ford and there’s a need for that liquids capacity?” It might be worthwhile to add greenfield projects to handle the differing commodities and markets.
Appalachian applications
One of the biggest logistical challenges to the infrastructure side of the business is how to move swelling production from the Marcel¬lus and Utica plays to market. The region had a negligible role in the modern industry until recent years, and midstream operators have had to scramble to serve producers.
Michael Huwar, vice president of marketing for TransCanada Corp.’s Columbia Midstream Group, told attendees at Hart Energy’s 2016 DUG East Conference in Pittsburgh that he sees “some great opportunities” for the region’s pipeline operators coming as early as next year.
“We’ve identified over $6.3 billion of regu¬lated growth out of the region and another $4 billion to $5 billion in modernization efforts to move gas for producers,” he said. Columbia has considered repurposing existing facilities, which he said the company “has done on many occasions.” It’s also added to its capacity via bigger pumps, compression and looping.
In addition, the company has looked care¬fully at related greenfield construction.
“It’s great to spend capital, to get projects approved. It’s great to grow your business, but at the end of the day, producers need a via¬ble way to get gas out of the region in a cost-effective manner,” Huwar said. “When you think about those greenfield projects, there are much higher costs that producers will have to bear. There are also issues around timing, permitting, construction and vast outreach challenges.”
Gone to Texas
Enterprise Products Partners LP announced its ATEX Express project in early 2012 to move abundant ethane production out of the Marcellus and Utica plays to the Mont Belvieu NGL hub east of Houston—and the multiple petrochemical plants along the Gulf Coast.
The 1,230-mile system consists of 595 miles of new pipe laid from Washington County, Pennsylvania, westward to Cape Girardeau, Missouri, using the right-of-way of an existing Enterprise line. At Cape Girardeau, Enterprise tied that new pipe into 580 miles of existing line—repurposed and reversed—to move eth¬ane south. At the Texas end, 55 miles of new line completed the ATEX link to Mont Belvieu. Service began in 2014.
With ethane prices stuck at record lows, it was important to keep tariffs comparatively low at around 15 cents per gallon. “By utilizing an existing pipeline and following an existing right-of-way for the section to be constructed, ATEX Express offers a cost-effective and timely solution that also minimizes the proj¬ect’s environmental impact,” Enterprise said when it announced the project. Initial capac¬ity was 125,000 bbl/d, expandable to 265,000 bbl/d as demand warrants.
Even with the cost savings from the repur¬posed assets, ATEX has been “a heavy anchor weighing down a number of Northeast E&Ps,” according to a recent Tudor, Pickering, Holt & Co. (TPH) report. Transportation costs have been barely covered at Mont Belvieu due to the commodity’s low prices. That could change dramatically starting in 2017, TPH added. “While this will likely remain the case for the next 12 months, we do potentially foresee the U.S. becoming short on ethane in the second half of 2017, forcing prices higher on the Gulf Coast,” the report said.
Eastbound, westbound
Even comparatively new midstream assets may need repurposing as the market changes, as illustrated by the Rockies Express (REX) Pipeline. REX had the misfortune of being a case study of an “it seemed like a good idea at the time” project. It was proposed at the start of the last decade to move abundant Rockies gas—where producers have long suffered con¬siderable differentials due to limited outbound capacity—to the gas-short Midwest.
REX is mostly 42-inch pipe and spans 1,679 miles from Meeker, Colorado, to Clarington, Ohio. The transmission system had the misfor¬tune of initial completion at the end of 2009—just as the booming Marcellus and Utica shale plays took hold. Instead of the Midwest needing gas from the far-off Rockies, Marcellus and Utica producers required access out of the Appalachians to nearby Midwest and Midcontinent customers.
The operator, Tallgrass Energy Partners LP, responded by converting the system’s eastern Zone 3 into a bi-directional header system. In 2015, Tallgrass received Federal Energy Reg¬ulatory Commission approval to modify Zone 3 so it could move 1.8 billion cubic feet per day (Bcf/d) of gas westward.
A further enhancement will boost bi-direc¬tional capacity to 2.6 Bcf/d in the fourth quarter as the heating season begins. REX also offers Appalachian producers 600 million cubic feet per day (MMcf/d) of westbound capacity through its Seneca Lateral in Ohio. Tallgrass proposes to make the whole REX system bi-di¬rectional by 2019.
More from the Marcellus
Repurposing assets can mean more than changing up pipelines. New terminals, docks and railyards may accompany a project. The stupendous production flows from the big Appalachian plays created a need for infra-structure improvements at the eastern end of the Keystone State.
Sunoco Logistics Partners LP closed its historic Marcus Hook refinery outside of Philadelphia in 2011. However, the com¬pany announced it would keep the plant’s related storage and dock facilities to handle growing Appalachian NGL production—a $2.5 billion project.
Its Marcus Hook Industrial Complex on the old refinery site has emerged as the East Coast’s premier gas liquids hub with the capability to receive and ship via marine, pipeline, truck and rail. It offers 3 million barrels (MMbbl) of underground storage. Marcus Hook served as the loading point for ethane exports in specially designed tankers, which started at the beginning of 2016.
Bakken needs
Bakken producers, which have had to deal with persistent takeaway constraints since the unconventional play blossomed, may finally get the pipeline capacity they need through combined new-build and repurposing projects. Energy Transfer Partners LP (ETP) currently is building the new 1,172-mile, 30-inch Dakota Access Pipeline from Stanley, North Dakota, to the Patoka, Illinois, pipeline hub. Meanwhile, ETP’s Energy Transfer Crude Oil Pipeline (ETCOP) repurposing project will be able to move Williston Basin production from Patoka to the Gulf Coast. ETP is reversing and repurpos¬ing a lightly used, 744-mile gas pipeline to link Patoka with the Nederland, Texas, crude hub.
Dakota Access was expected to go onstream late this year but securities analysts now proj¬ect a 2017 start-up due to regulatory delays in Iowa and tribal protests in North Dakota. Initial transport will be 450,000 barrels a day (bbl/d), according to ETP; capacity will be 570,000 bbl/d.
The projects may flip the lingering capacity question for the Bakken. Jean Ann Salisbury, senior analyst for Bernstein Research, reported earlier this year that falling Bakken output and the completion of Dakota Access and its ETCOP link “will leave the basin with excess transport capacity.”
So will another repurposing in the upper Midwest come along in a few years? It’s possible.
Seaway: every which way
Repurposing can happen multiple times on one system and with differing products. No project better illustrates how adaptable midstream infrastructure can be in meeting producers’ needs than the Seaway system that links the Midcontinent with the Texas Gulf Coast. Originally laid in the 1970s as Seaway Pipeline by Phillips Petroleum Co. and sev¬eral partners, the 30-inch, 500-mile line went in place to move imported crude north from Gulf ports to feedstock-short inland refineries. But the industry’s economics changed in the early 1980s downturn, and the pipeline became inactive.
In 1984, Phillips bought out its partners and converted Seaway to a southbound gas system moving Midcontinent producers’ gas to fuel Phillips’ Sweeny, Texas, refinery and other Gulf Coast plants. A new name went up out front of the line’s stations as work crews swapped compressors for pumps—Sea¬gas Pipeline.
But wait, there’s more: Atlantic Richfield Co. bought the line in 1995 and switched it back to a northbound crude hauler (and its old name), moving oil to ARCO’s terminal at the Cushing, Oklahoma, storage and pipeline hub. Owner¬ship changed over the years with Enterprise Products Partners LP gaining a 50% interest and operatorship in 2005 with Enbridge Inc. holding the other 50%.
The rise of shale oil production from the Bakken, Permian and Midcontinent plays brought another change to Seaway in 2012 when the partners reversed flow yet again, making the line a 400,000 bbl/d southbound operation. They looped the line in 2014 as shale production continued to swell, raising Seaway’s capacity to 800,000 bbl/d to help ease Cushing’s storage glut.
‘Sucker-punched’ producers
The greatest repurposing opportunities typically lie in regions that have had years of production before recent unconventional drill¬ing upticks. Consider East Texas, which first boomed in the 1930s. True to the old adage that the best place to find oil is where it has been found already, the region has its own unconventional plays in the Eaglebine and Haynesville. Geologically an extension of the Eagle Ford to the southwest, the Eaglebine centers on an 11-county area north of Houston where the Eagle Ford meets the Woodbine.
RBN Energy LLC noted in a report in May that “the Eaglebine is an ‘emerging’ shale play that never quite emerged,” since the oil price collapse that started in mid-2014 “suck¬er-punched Eaglebine drillers and producers just as they were ramping up their output, benefiting from new pipeline takeaway capac¬ity and dreaming big.”
Greenfield developments wouldn’t pay. But how to move out the new production? The answer came in repurposed brownfield assets and a tweak to one new asset built to serve the far-off Permian Basin.
“Despite the Eaglebine’s proximity to Houston, the play’s continued development was hampered somewhat by a lack of pipeline takeaway capacity,” the RBN report added. “In fact, until late 2014 (when Eaglebine production was surpassing 100,000 bbl/d) there were no pipelines in place to move Eaglebine crude to Gulf Coast terminals and refineries; instead, virtually all of the oil pro¬duced there was moved by truck—a cumber¬some and costly practice that ate into producer netbacks.”
The first pipeline capacity added for Eaglebine crude producers came through a flow reversal of Sunoco Logistics’ existing, 10-inch Mag-Tex products pipeline, which runs from near Nederland, Texas, to Suno¬co’s Hearne, Texas, terminal. Renamed the Eaglebine Express, the line has a capacity of 60,000 bbl/d. Meanwhile, Koch Pipeline Co. restarted a portion of an unused crude pipeline in the region.
The play also gained transport capacity thanks to Magellan Midstream Partners LP and Plains All American LP, which are build¬ing an Eaglebine terminal on their Perm¬ian-focused BridgeTex Pipeline that happens to cross the Eaglebine region on its way to the Gulf Coast. Capacity for the Grimes County, Texas, operation reportedly will be 35,000 bbl/d and service will start in mid-2017.
I.J. (Chip) Berthelot, president and CEO of Azure Midstream Partners LP, one of the area’s major midstream players, believes “East Texas is one of the greatest fields in the nation,” although activity has slowed. The region’s proximity to the Gulf Coast will be a plus as domestic gas and LNG export demand grows.
When that happens, “we think that the major—the main—impact will be support of pricing against other parts of the country that may see more substantial basis differential discounts, thus lower wellhead netback pric¬ing,” Berthelot added, and that could sustain new midstream assets.
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