“Don’t throw the past away, You might need it some rainy day, Dreams can come true again, When everything old is new again.”

Singer and songwriter Peter Allen certainly didn’t have North America’s energy infrastructure in mind when he wrote his paean to renewed love. But the lyrics fit.

The midstream buildout, which always follows 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 expensive as regulatory approvals, environmental worries, costs and public not-in-mybackyard 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 rightof- way purchases, construction costs and no doubt some confrontations with recalcitrant farmers.

Another creative Williams repurposing project, in 2015, converted an empty airplane hangar at New York’s historic Floyd Bennett Field in Brooklyn, 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 assets may be frequent, the idea doesn’t always work, according to James P. Benson, a founding partner of Dallas-based Energy Spectrum Capital. Midstream operators must determine what assets they have—and then what producer customers 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.

“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 significant 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 repurposing 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 Marcellus 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’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 next year.

“We’ve identified over $6.3 billion of regulated 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 carefully 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 viable 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, Pa., westward to Cape Girardeau, Mo., using the rightof- 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 ethane 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 rightof- way for the section to be constructed, ATEX Express offers a cost-effective and timely solution that also minimizes the project’s environmental impact,” Enterprise said when it announced the project. Initial capacity was 125,000 bar rels per day (bbl/d), expandable to 265,000 bbl/d as demand warrants.

Even with the cost savings from the repurposed 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 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 considerable differentials due to limited outbound capacity—to the gas-short Midwest.

It is big. REX is mostly 42-inch pipe and spans 1,679 miles from Meeker,Colo., to Clarington, Ohio. The transmission system had the bad luck to reach 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 had to have access out of the Appalachians to nearby Midwest and Midcontinent customers.

The operator, Tallgrass Energy Partners, responded by converting the system’s eastern, Zone 3 into a bidirectional header system. In 2015, Tallgrass received Federal Energy Regulatory 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-directional 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 of westbound capacity through its Seneca Lateral in Ohio. Tallgrass proposes to make the whole REX system bidirectional by 2019.

Energy Transfer Partners LP (ETP) is currently building the new 1,172-mile, 30-inch Dakota Access Pipeline from Stanley, N.D., to the Patoka, Ill., pipeline hub. Meanwhile, ETP’s Energy Transfer Crude Oil Pipeline repurposing project will be able to move Williston Basin production from Patoka to the Gulf Coast. ETP is reversing and repurposing a lightly used, 744-mile gas pipeline to link Patoka with the Nederland, Texas, crude hub.

These projects may flip the lingering capacity question for the Bakken. 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 and with differing products. No system 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 several 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 went 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—Seagas 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. Ownership 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 yet 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 drilling 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 unconventionalplays 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 noted in a recent research report that “the Eaglebine is an ‘emerging’ shale play that never quite emerged,” since the oil price collapse that started in mid-2014 “sucker-punched Eaglebine drillers and producers just as they were ramping up their output, benefiting from new pipeline takeaway capacity, 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 produced there was moved by truck—a cumbersome 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 fro near Nederland to Sunoco’s Hearne, exas, 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 region also gained transport capacity thanks to Magellan Midstream Partners LP and Plains All American LP, which are building an Eaglebine terminal on their Permian-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 the middle of 2017.

I.J. (Chip) Berthelot, president and CEO of Azure Midstream, one of the area’s major midstream players, believes “East Texas is one of the greatest fields in the nation,” although current activity has slowed. The region’s close proximity to the Gulf 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 pricing,” Berthelot added, and that could sustain new midstream assets.

An LNG advantage

The unconventional plays brought a sea change to the view of U.S. oil and gas assets. As recently as 10 years ago, most in the industry viewed the U.S. as a long-term gas importer. That led to construction of multi-billion dollar LNG import terminals with docks, insulated tanks and gasification systems to handle gas shipped via tankers from the Mideast and Africa.

It didn’t turn out that way.

U.S. shale gas production reversed the equation and made the nation a prospective gas exporter. In an epic example of midstream repurposing, those LNG import terminals have proved to be major assets that knock billions of dollars off construction for proposed LNG export operations.

That may prove to be a major asset for export players facing competition from more costly greenfield LNG operations in Australia and the Middle East.

Cheniere Energy Inc. bolted on new liquefaction trains to its existing import dock and tank farm in Cameron Parish, Louisiana, becoming the first largescale U.S. LNG exporter early this year. Next up will be Dominion Energy’s Maryland’s Cove Point terminal on Chesapeake Bay. Built in 1978 and lightly used since, Cove Point’s infrastructure will instead support exports when its first liquefaction train goes online at the end of 2017.

The Golden Pass import terminal at Sabine Pass, Texas—across the Sabine River from Cheniere’s operation— plans to start LNG exports by 2021, using its existing facilities coupled to new liquefaction assets. Partners are Qatar Petroleum, ExxonMobil and ConocoPhillips.

Making it work

Midstream infrastructure works best as an integrated whole, and with all of the mixing and matching of repurposed assets and new facilities—it may take a while for North America’s vast midstream network to settle down and work most efficiently.

RBN Energy noted in a research report, “Stairway to Houston,” published late last year just how big the changes have been at just one locale—Houston— and how everything must fit together to serve producers most efficiently.

“Prior to 2012, the only U.S.- produced crude delivered by pipeline to Houston-area refineries came from offshore Gulf of Mexico or onshore Louisiana fields,” the report noted. “The majority of supplies were imports delivered by waterborne tanker. But in just three short years between 2012 and 2015, roughly 2 MMbbl/d of crude pipeline capacity was built or repurposed to deliver surging light shale crude production and heavy crude from Canada into the Houston area.

“Refiners have adapted quickly to take advantage of new sources of supply,” it added. “But with much of the newly minted infrastructure underutilized, midstream companies still need to improve pipeline connectivity and storage accessibility to overcome area logistical challenges.”

The nation’s expansive midstream sector will adjust, as it has before. U.S. producers will continue to enjoy the world’s best infrastructure network, helping to keep costs low and netbacks high. Repurposing the old to make everything new again will keep it that way.