The East Coast businessman was on his first-ever trip out to Houston and Texas. Standing at the window of a major gas transmission system’s high-rise headquarters, he surveyed the thick urban forest that stretched out to the horizon 20 stories below. The Bayou City nestled down in its green carpet like ladybugs in a parsley bed.

It was not what he expected. Thoughts of all the iconic, dusty John Wayne westerns about Texas he had seen, set amid dry buttes, cactus and Longhorn cattle, came to mind.

“This doesn’t look like Texas!” he exclaimed to his bemused hosts.

► Join us in San Antonio for Midstream Texas, Sept. 12-14.

The visitor in that moment learned an important lesson about the Lone Star State: It is a big land of contrasts and surprises. Like the state’s topography, its multiple unconventional plays vary widely. What’s happening now in East Texas with the Eaglebine and Cotton Valley, or South Texas’ Eagle Ford, looks much different than, say, the booming Permian Basin out west.

New directions

And on a macro scale, the energy industry’s assumption that production will always fl ow to the north and east has become outdated. New midstream infrastructure will move production in new directions—east and out to sea and south into Mexico. All of those changes will inspire discussion topics at Hart Energy’s 2nd annual Midstream Texas conference, set for Sept. 12-14 in San Antonio.

Energy always is a big state topic. In total, Texas produces around 3.2 million barrels of oil a day (MMbbl/d). If Texas were still a separate country—and a native Texan will quickly remind you that was once the case—the state would rank just behind Canada and well ahead of such international energy powerhouses as Iraq, Iran, the United Arab Emirates and Mexico as a crude producer.

And what about natural gas? Texas wells fl ow somewhere around 21 billion cubic feet per day (Bcf/d), the biggest slice of domestic natural gas production, currently estimated at around 73 Bcf/d.

All of that massive output has to be gathered, processed, transported and stored for customers. That is the Texas midstream. That is a big and diverse job.

The INGAA Foundation published its periodic midstream infrastructure update, “North American Midstream Infrastructure Through 2035: Leaning into the Headwinds,” in the second quarter that had a lot about to say about Texas in its roughly 20-year projections. For example, consider potential employment. The report projects roughly one in six of all the new midstream jobs that will be created in North America through 2035 will be in Texas. That’s double the potential job creation expected for Pennsylvania, ranked a distant second.

The INGAA Foundation report projects total North American midstream capital expenditures of a low-case $471 billion to high-case $621 billion through 2035. The study doesn’t break out that spending by state, but its Texas-centric Southwest region, consisting of Texas and its four border states, gets by far the largest serving of the capex action.

Texas already enjoys midstream infrastructure in place that’s second to none. The Texas Railroad Commission counted 431,997 miles of pipeline in the state’s soil at the end of 2015, up 6% in just three years, thanks to the booming unconventional shale plays.

So much for the state’s big picture. Drilling down to regional and local levels reveals a variety of unique issues, Greg Haas, director, integrated oil and gas research at Stratas Advisors, told Midstream Business.

“Local issues—opportunities and challenges. There are two different sides of the same coin these days in Texas,” Haas said, noting the state’s energy diversity.

Permian perspectives

So where are the opportunities? That’s easy: the Permian. It’s the one unconventional play that has bucked the trend of sharply lower activity during the current downturn because of its multiplay/ multi-pay geology and in-place midstream infrastructure.

“Of course, the Permian is going gangbusters,” Haas said “As far as oil infrastructure, and gas and NGL infrastructure throughout the producing regions of Texas, it looks like the Permian is the one that will have the majority of the growth for the next several years.

“That could proceed past 2020 in terms of the preeminence, in terms of its growth position relative to other plays in the country,” he added. “And, that would mean that if you’re gathering or if you’re processing, or if you’re fractionating, and you have proximity and/or access to the new barrels or new gas coming out of the Permian, then that’s probably part of your growth story as a midstream operator.”

Kurt King, partner at Opportune, an energy management consulting firm, agreed.

“I think it’s fairly obvious that the Permian is the most economical play right now,” King told Midstream Business. “There is the continued buildout of gathering and takeaway capacity in that region—to get oil to as many markets as midstream operators can from an optionality perspective; to get oil and condensate to the Gulf in particular. And when it comes to natural gas, the focus is more on exports to Mexico or down to the LNG plants on the Gulf Coast.”

Statistics show production has remained comparatively strong in the Permian, although it, too, saw an output decline in the first half. The Permian rig count is down, but increased drilling efficiency and higher initial production rates have offset that decline in part. The big play has multiple players in multiple areas that have earmarked capex to handle what they believe will be growing production flows for years to come.

Texas will see a strong in-state market for increasing production due to its vibrant and diversified economy. That’s particularly true for natural gas and NGL. A recent Scott Madden study projected that Texas utilities in the Electric Reliability Council of Texas (ERCOT) grid area will add 20 gigawatts of new, gas-fired generating capacity by 2020. ERCOT’s peak power demand of 69.9 gigawatts came in August 2015.

Multiple midstream operators and upstream producers have been putting capital to work to expand and rework the Permian’s gathering and processing network. Reliance Energy, which owns approximately 40,000 net acres in the prolific Northern Midland Basin, gained an investment in its crude gathering affiliate, Reliance Gathering LLC, from Metalmark Capital in the second quarter. Reliance Energy said the deal will help it continue to scale up its in-house gathering system.

ONEOK Partners has earmarked $540 million for multiple projects to serve its Permian customers. It will be adding significantly to its gas processing capacity in the second half, building on a processing business that averaged 195,000 bbl/d of NGL in first-quarter 2016.

Meanwhile, the company is expanding its WesTex Transmission pipeline, adding two new compressor stations and enlarging three existing stations. Capacity will grow by 260 million cubic feet per day (MMcf/d) when the $100 million expansion project wraps up in first-quarter 2017.

Mexico-bound All those new assets will tie into ONEOK’s new, Mexico-bound Roadrunner Gas Transmission system, the first phase of which went onstream in March with a capacity of 170 MMcf/d. The firm scheduled the second phase to go in service in first-quarter 2017, and the final phase in 2019. When completed, Roadrunner will have a capacity of 640 MMcf/d.

ONEOK and Mexico’s Fermaca have a 50:50 joint venture (JV) in Roadrunner.

Meanwhile, Energy Transfer Partners received Federal Energy Regulatory Commission (FERC) approval in May for its proposed Trans-Pecos Pipeline that also will take gas south. The 143- mile, 42-inch pipeline is proposed to transport up to 1.3 Bcf/d of gas, crossing the border into Chihuahua state at Presidio, Texas.

“Mexico is definitely a place where growth should come and continue to be built out, in terms of natural gas and also, we believe, propane and perhaps other NGL,” Haas said.

The Permian’s Delaware Basin may be the best-of-the-best unconventional plays right now. SGS Equity Research opined at the end of the second quarter that it had “increased confidence in the Delaware Basin (best positive rate of change basin).” Multiple producers have moved into the region, and that means growing demand for multiple midstream services.

Enterprise Products Partners is investing substantial capital in the Permian in general and the Delaware in particular. In late June, it announced plans to move ahead with a new Delaware gas processing plant. A final site has not been selected for a facility that is expected to have a capacity of 300 MMcf/d, capable of extracting 40,000 bbl/d of gas liquids. Start-up could come in second-quarter 2018. As with other Delaware players, Mexico’s need for gas was part of the equation in the firm’s announcement of a third new gas plant in two years, Enterprise noted.

Meanwhile, Enterprise finished up a major expansion of its South Eddy cryogenic gas plant on the Texas-New Mexico border in the second quarter. The plant can process 200 MMcf/d of gas and extract 25,000 bbl/d of NGL. The expansion included 90 miles of new gathering lines and 71 miles of transmission lines. Enterprise expects to place its 150 MMcf/d Delaware Basin cryogenic plant on line in the third quarter. The plant will be able to produce 20,000 bbl/d of NGL. Occidental is a 50/50 JV partner.

Headed for Houston

Enterprise’s vast Permian pipeline network will feed into its new Midlandto- Houston crude oil pipeline, now scheduled to enter service in mid-2018. The 416-mile, 24-inch pipeline is expected to start at 300,000 bbl/d, which can be expanded to 450,000 bbl/d with additional pumps. Enterprise said in a June investor report that 60% of the line’s initial capacity is under contract. It will handle four crude grades: West Texas sour, West Texas Intermediate (WTI), light WTI and condensate.

The east end of the line will be Enterprise’s Sealy, Texas, terminal, west of Houston. From there, WTI and other Permian crudes can move through the vast network of pipelines that interlink the Gulf Coast’s multiple refineries, chemical plants and docks.

Will the midstream overbuild in West Texas? All those Permian midstream projects may be too much of a good thing, Stifel said in a recent analyst report.

“While we agree it will be the basin that holds up best, we also believe given the intense focus on the Permian, not only by MLPs but other companies as well, it is highly competitive, which may impact returns of new projects,” it cautioned, a caveat sounded often about other Texas shale plays.

Finding the challenges

And where are the state’s challenges? They are there, as surely as the West Texas’ dry buttes contrast with East Texas’ swampy Piney Woods.

Other Texas shale plays have suffered in comparison to the Permian due to the commodity price slump. Drilling in the Eagle Ford, East Texas and elsewhere has dropped precipitously. That’s part of a broader national trend, of course, and one reason why a recent Robert W. Baird & Co. analyst report cast a gloomy view of midstream infrastructure expansion everywhere in the near future.

“Expectations for midstream capital investment have deteriorated materially as lower oil prices, coupled with capacity overbuild, weigh on demand for new pipelines,” Baird said. “From the top down, INGAA’s multi-year investment outlook… lopped ~30% off its prior forecast. From the bottom up, this foots with economic, environmental and NIMBY [not in my backyard] project obstacles. Consensus intermediate-term estimates have been slower to reset for pipeline construction contractors, specifically MasTec and Quanta Services, where we are incrementally cautious, whereas MLP equities rapidly digested the new reality.”

Moody’s Investor Service agreed in a June report.

“The plateauing of and projected decline in midstream capital spending follows five years of booming expansion to serve the rapid growth of U.S. shale plays. While natural gas demand growth will afford midstream investment opportunities over the coming decades, capital spending will likely remain subdued into 2017, and the recent pace of rapid growth will be difficult to replicate,” the report said.

The ‘iffy’ Eagle Ford

The once-booming Eagle Ford may be a case in point, according to Stratas’ Haas.

“I would say Eagle Ford is kind of iffy right now,” he said. “That’s the challenge side of the coin. The Eagle Ford is challenged by relatively low prices and relatively high drilling costs vis-à-vis some of the opportunities elsewhere.” Haas noted the Eagle Ford has a large number of drilled but uncompleted (DUC) wells that could be completed and brought on comparatively quickly—if commodity prices warrant. That could bring a quick turnaround in the play’s fortunes and new in-flows to the region’s comparatively strong midstream infrastructure if the DUCs take off.

“The Eagle Ford is pretty well built out from a midstream perspective,” he added. It’s also close to important markets, including the Gulf Coast. The play lies close to Mexican markets—the western end of the Eagle Ford actually runs under the Rio Grande into northern Mexico—and it produces the gas and NGL Mexico wants. New pipeline capacity could enhance demand once commodity prices turn.

East Texas

If the big action now is out west in the Permian, it’s important to remember back when East Texas was the big oiland- gas player. The East Texas boom of the 1930s put oil towns such as Tyler, Longview and Lufkin on the map.

And true to the old adage that the best place to find oil is where it has already been found, 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.

“The Eaglebine is an ‘emerging’ shale play that never quite emerged, mostly because 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,” RBN Energy said in a recent research report.

All those drilling rigs that suddenly popped up along Interstate 45 disappeared as prices cratered in late 2014.

I.J. “Chip” Berthelot, president and CEO of Azure Midstream, one of the area’s major midstream players, told Midstream Business that he 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 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 pricing,” Berthelot added.

But midstream infrastructure—or a lack of it—remains a regional issue, RBN said.

“Despite the Eaglebine’s proximity to Houston, the play’s continued development was hampered somewhat by a lack of pipeline takeaway capacity,” the 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.”

Using what’s there

That midstream bottleneck led to a common sector response: repurpose existing assets. The first pipeline capacity for Eaglebine crude producers came through a flow reversal of Sunoco Logistics’ 10-inch Mag-Tex products pipeline, which runs from near Nederland, Texas, to Hearne, Texas. Renamed the Eaglebine Express, the line has a capacity of 60,000 bbl/d.

Koch Pipeline Co. restarted a portion of an unused crude pipeline in the region and Magellan Midstream Partners and Plains All American are building an Eaglebine terminal on the Permian-focused BridgeTex Pipeline that, thanks to some midstream serendipity, crosses the Eaglebine region. Capacity for the Grimes County, Texas, operation reportedly will be 35,000 bbl/d.

Down Mexico way

The Mexican market could prove particularly valuable to Texas producers and midstream players, as the multiple projects mentioned above illustrate.

Kimberly Dang, Kinder Morgan’s CFO, rated exports to Mexico a top driver for new gas demand in a June investor presentation—along with new domestic petrochemical plants (many of which will be along the Texas coast), LNG exports and power generation. Kinder Morgan serves Mexico through the Sierrita Gas Pipeline in Arizona, which connects with its big El Paso Natural Gas system line that links Texas gas producers to California customers. Most of the gas Sierrita moves comes from Texas wells. Kinder Morgan announced plans earlier this year to add compression to Sierrita, boosting capacity on the 61-mile, 36-inch line to 431,100 dekatherms per day (Dth/d) from 200,846 Dth/d.

Howard Energy Partners, in a JV with Mexico’s Grupo Clisa, began construction on its Nueva Era Pipeline in July. It will move gas—primarily coming off Howard’s extensive Eagle Ford gathering and processing network—under the Rio Grande at Webb County, Texas, south to the industrial hub of Monterrey.

Mexico’s power utility, Comisión Federal de Electridad (CFE), will be Nueva Era’s anchor shipper and has booked 504 billion Btu per day of capacity on the 30-inch, 190-mile line. Scheduled in-service date is June 2017.

Spectra Energy and TransCanada Corp. won $3.6 billion in contracts in the second quarter to build a 665-mile, 2.6 Bcf/d pipeline that will run from the Agua Dulce gas hub west of Corpus Christi, Texas, to Brownsville, Texas, then offshore along Mexico’s coast to the port of Tuxpan.

Spectra will build a $1.5 billion pipeline from Agua Dulce to the coast on the U.S.-Mexico border while TransCanada will lead a project to build the connecting, $2.1 billion Sur de Texas line from the border beneath the Gulf of Mexico. The Texas portion, expected to come online in 2018, will be part of Spectra’s Valley Crossing Pipeline. CFE is the Mexican partner.

That’s a lot of new pipe headed south; can Texas supply gas for all those lines? The better question might be: What gas demand will there be? Haas replied.

“I think there is announced a pretty substantial amount of new cross-border pipeline capacity,” he added. “So it might take a little bit of time for the economies on both sides of the border to absorb and complete all that infrastructure, and then deliver the flows and start using all that natural gas in the Mexican economy. But this is still a very positive growth story.”

Product potential

Mexico also wants petroleum products and Howard Energy has its Dos Águilas products pipeline on the drawing board, which will move 72,000 bbl/d from Corpus Christi refineries and Howard’s Brownsville terminals to customers in northern Mexico. Service is expected to start in first-half 2018; the line could be expanded to 90,000 bbl/d.

And Mexico offers more than just pipeline projects for midstream growth potential.

Rangeland Energy announced construction of its STEPS (South Texas Energy Products System) terminal in Corpus Christi earlier this year. The 190-acre operation will receive, store and ship petroleum products and LPG to Mexican customers via the adjacent Kansas City Southern Railway and its Kansas City Southern de México subsidiary. The first phase of the STEPS project will open to manifest service in first-quarter 2017 and unit trains later in the year. Construction of a second phase is scheduled, pending agreements with customers at major Mexican cities.

South of the border, Watco Cos., a major rail, terminal and port services firm, signed an agreement in the second quarter with WTC Industrial to design, build and operate a unit train liquid fuels terminal and general cargo facility at WTC Industrial Park in San Luis Potosí, Mexico. The terminal is on the Kansas City Southern de México. Operations will begin at year-end 2016 or early next year, Watco said.


Going coastal

Texas midstream operators enjoy the opportunity to serve both ends of the value chain—producers and customers. The Texas-Louisiana Gulf Coast represents the largest concentration of downstream refining and petrochemical capacity in the world.

But the jewel in that Texas midstream crown may be the sprawling NGL storage, fractionation and pipeline hub at Mont Belvieu, east of Houston. Its importance will only grow as the NGL market grows, according to a recent Deutsche Bank analyst report that focused on an analysis of major, diversified NGL players—in particular DCP Midstream Partners, Enterprise, MPLX and ONEOK.

“Investors continue to want to play the burgeoning NGL recovery theme, particularly for ethane as cracker/export demand is set to ramp through 2017-18,” the report said. “Questions are focused on the ability to run higher volumes and overall asset integration/connectivity to Mont Belvieu. We agree that several of these names should see related cash-flow growth, but we think investors need to differentiate between basins (relative transportation costs) and understand company-specific drivers. Rolling volumes in some plays remain a material headwind… that could outweigh any impact from improved NGL prices.”

Mont Belvieu may be a cornerstone of the Texas midstream but it, too, has seen changes recently. For example, Enterprise Products’ ATEX Pipeline that moves ethane southwest from the Marcellus and Utica to serve the ethane cracking capacity centered on the Gulf Coast.

NGL demand indeed will be going up, thanks to new domestic petrochemical capacity and exports, all to be supplied by those new gas plants in the Permian, Haas emphasized.

“I think that the newer plants will have higher efficiency and be able to extract deeper cuts of NGL,” he said.

“The newer gas plants, which you still have to build in large measure in places like the Permian, will continue to ratchet up recoveries and probably help economics overall.”

Enterprise has emerged as a preeminent exporter through its extensive storage and terminal assets along the Gulf Coast. Estimates have placed its waterborne exports of propane and butane at more than 700,000 bbl/d. A new 200,000 bbl/d ethane operation, opening in the third quarter, will boost exports of the NGL that has been in chronic oversupply.

The company expects to add ethylene to that product mix. Enterprise estimated a 40% increase in U.S. ethylene production in the next few years and forecasts much of that output will go to foreign markets, particularly Asia.

LNG heats up

Cheniere Energy started up the nation’s first, large-scale gas liquefaction and export operation earlier this year just across the Sabine River from Texas in Cameron Parish, La. West of the Sabine, LNG represents another export opportunity for Texas as the U.S. LNG export business grows.

If all of the proposed liquefaction plants along the Texas coast were built—and that looks doubtful—the state would gain 17.1 Bcf/d in new gas demand—or about three-quarters of the gas the state produces now. While the softening demand for LNG probably means some of those proposals will be shelved, contractors are moving dirt now for FERC-approved plants.

Freeport LNG has construction underway on its greenfield LNG plant and terminal in Brazoria County, Texas.

It scheduled the first train to go online in 2018 with peak production of 2.8 Bcf/d set for early in the next decade. Boardwalk Pipeline Partners’ Gulf South Pipeline received a FERC permit in June for its Coastal Bend Header project, which will transport up to 1.42 Bcf/d of gas to the plant. The header will include a 66-mile, 36-inch lateral and compressor stations in Brazoria and Wharton counties. The cost is expected to be $545 million, according to Gulf South.

Oil on the water

And then there is the opportunity—and current challenge—for Texas crude exports, thanks to the repeal of the 40-year-old export ban at the end of 2015.

The industry had high hopes for U.S. crude sales abroad but the business has not expanded as quickly as some observers expected, thanks to the current worldwide crude glut. But U.S. crude exports are happening, nonetheless. The business could have great potential once international oil supplies fall in line with demand, many analysts say. Enterprise said in its first-quarter earnings call that it exported 165,000 bbl/d of crude oil in the quarter with condensate making up about one-third of that volume.

Petroleum product sales abroad have been strong for several years as the U.S. turned from being a product and LPG importer to an exporter, thanks to rising production from the shale plays.

Green Plains and Jefferson Gulf Coast Energy Partners, a subsidiary of Fortress Transportation and Infrastructure Investors, announced at the end of the second quarter a JV to build an intermodal export and import fuels operation at Jefferson’s Beaumont, Texas, terminal. Phase I, to open secondquarter 2017, will handle primarily ethanol, but further development of the JV is expected to add the ability to manage imports and exports of petroleum products.

Haas cautioned the current export opportunities could quickly turn into challenges.

“The loading terminals, the marine terminals, both from crude and from LPG and NGL perspectives, are pretty much overbuilt already, we think,” he said. “On the natural gas exports side, LNG, given the low energy price scenario that we are in—lower for longer—we don’t see a lot of those terminals being started up. Everything that we see is slowing down their progression towards completion and commercial service. So for LNG, propane, LPG and crude oil, it begs the question: Do we need any more terminals than what we have presently?”

King has a more optimistic viewpoint on a further buildout along the Texas coast. Given recently completed, and pending, pipeline capacity, “there are a lot of product terminals in the Houston Ship Channel area that people are trying to build for their storage and export capabilities,” he said. “And everything I’ve seen is that Corpus Christi is continuing to be built out. It’s emerging as a viable outlet for the Eagle Ford and as a conduit to Mexico, the rest of the Gulf Coast and even internationally.”

Panama Canal

What could prove to be an overall export game changer is how the longawaited Panama Canal expansion will impact Texas energy exports. The canal’s bigger locks could economically open Pacifi c and Asian markets to Gulf Coast shippers, allowing them to compete evenly in Asia with Mideast suppliers.

The very fi rst vessel to transit the canal following dedication ceremonies at the end of June was NYK Line’s Very Large Gas Carrier Lycaste Peace, transporting propane loaded at a Houston Ship Channel terminal to a customer on Tokyo Bay. Mitsubishi Heavy Industries modifi ed the ship, built in 2003, for use as a New Panamax-class tanker.

“What remains to be seen, though, is how many other supersized vessels carrying propane, LNG or other hydrocarbons will follow, and how soon?” RBN asked in a report examining the potential impact of a bigger canal on the Gulf Coast.

“The international energy trade has been shifting toward larger and larger sea-going vessels, seeking to maximize economies of scale and minimize shipping costs. That shift has been stymied somewhat, though, by the Panama Canal’s inability—until now—to handle the vast majority of the world’s LNG and liquefi ed LPG carriers.

“While it may take some time for U.S. hydrocarbon exporters to take full advantage of the now bigger-and-better Panama Canal, the good news is that the expansion is fi nally done, and that the canal holds the promise of lower shipping costs from the Gulf Coast to Asia, which can only help U.S. exports in the long run,” RBN added.

M&A action

Opportune’s King said the downturn has had a predictable fi nancial impact on midstream operators, even though they don’t have the commodity price exposure that their producer customers face.

“We’re seeing what I call ‘friendly acquisitions’ from related parties,” he said. “I think the entrenched players and early movers into these plays, which built out assets and have a good track record on how to operate with producers in the area, are looking at some of the late entrants in those regions that want to exit. The late entrants now want to exit and consolidate around their core areas in other parts of the country. It’s a good way for the established players to acquire assets at a good valuation.

“We’re also seeing companies buying out joint-venture partners,” King added. “A weaker partner might need cash, so it’s a way for the stronger partner to acquire 100% interest and focus on that region. We’re also seeing companies buy out affiliates.”

Turning the corner

So when will the commodity price turnaround come? Perhaps, just perhaps, it has already started.

Commodity prices have ticked upwards from lows set last February. But several things will have to occur to bring a true rebound, Richard Hastings, macro strategist for Seaport Global Securities, told Midstream Business.

“I believe the turnaround story will be a combination of price, and then further out into the future, expectations for product demand growth,” Hastings said, adding “the Eagle Ford may need prices to trend a bit higher than $55 for quite some time. The Eagle Ford has a notable decline trend already, and it is estimated that about 70% of recent production in the Eagle Ford production might be coming from wells completed in 2014 and 2015. This means the decline rates are going to kick in soon, creating a tough situation for supply.

“The Eagle Ford is more mature than [unconventional] parts of the Permian, but it might require slightly higher prices, and for longer, in order to rebuild sufficient rig action to crank out new crude from new wells,” Hasting added.

“Even if prices rebound sufficiently, the time frame for a rebuild of the Eagle Ford from trough back to peak production involve[s] at least another three years. And by 2020, there could be more fears about future product demand such as electric car displacement of gasoline demand in passenger vehicles. It’s a tough situation, with few ordinary historical comparisons,” he said.

Looking ahead

There are a lot of things happening now—both opportunities and challenges—but the sector needs to bear in mind that Texas, overall, ranks second to none in its ways to create midstream growth, according to Haas.

“I would say the only other major area that still has a lot of infrastructure that could potentially come, and could potentially add some great value, in the U.S. is the Appalachian region,” he added. “The infrastructure that I can see being very helpful up there would be gas pipelines to distribute the gas to the major consuming regions of the Northeast, and then the pending power plants.”

What does the Texas midstream need that it does not have?

Haas rated that “a good question.

As far as the builders of infrastructure today, what do you still need going forward? That really depends upon how you view the upstream production forecasts and outlooks into the future. If you believe that we will be getting more investment into upstream and downstream, then you have to look and see which plays are the most prone to have that investment happen. That certainly is the Permian.”

But in addition to multiple unconventional play growth prospects, the Texas midstream enjoys another advantage: A generally positive public attitude toward the industry that contrasts with those NIMBY opponents mentioned in the Baird report. Most energy-industry projects in the Marcellus and Utica “are being vigorously opposed by opponents of any fossil fuel whatsoever, and of course from landowners now that are looking not to have infrastructure like that in their backyards,” Haas noted.

That opposition could lead to an “infrastructure build-out focused on localized consumption even of NGL, including in the form of petrochemical plants up in the Northeast. If that happens, the midstream infrastructure in Texas will be affected by lower volumes of NGL coming from Appalachia to Texas, and that means then that Texas may have lower throughputs, lower export opportunities, and even lower feedstock flows, lower storage and tariffs associated with that for the midstream in the NGL space,” he said.

But for now, much of the production in the Marcellus and Utica ends up moving south, thanks to ATEX and other lines. The biggest collection of refineries and petrochemical plants lie in Texas and across the border in Louisiana and that’s likely to be the case for some years to come.

“So it’s all eyes really on Texas versus Appalachia right now, and depending on if and how Appalachia gets built out, Texas may or may not maintain market share or have some of that market share and all that volume and all that economic activity sort of being pulled northward up into Appalachia, where so much of this NGL and gas can be produced,” Haas said. “So it’ll be interesting to see in the next five years which region can either hold or can gain in market share.”

That shapes up as one more opportunity, and one more challenge, to the sprawling and varied Texas midstream.

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