As the threat of too much oil and gas—and too few pipelines serving the Permian Basin—continues to loom, midstream developers are trying to keep up with producers’ aggressive pace by creating export opportunities.

Exports to Mexico and to Texas’ seaports are the new goals. Gone are the days when in-state oil and gas production went primarily to in-state refineries and petrochemical plants.

At some point Permian production is going to exceed current takeaway capacity, Robb Barnes, senior vice president of commercial-crude oil at Magellan Midstream Partners LP, said in his opening keynote at Hart Energy’s third annual Midstream Texas conference in Midland.

Magellan is one of several midstream firms looking to lay a new pipeline from the Permian to Corpus Christi, Texas, and it is expanding its BridgeTex Pipeline in the basin.

Reaching water
“The rationale around laying a pipeline from the Permian down to Corpus Christi,” he said, “is to get it on the water”—a capability being pushed by producers.

This year’s conference featured a Permian-centric view since the big play continues to increase production while the Lone Star State’s other unconventional plays, such as the Eagle Ford and Barnett, await better commodity prices. The conference drew a record attendance of more than 600.

Despite relatively flat oil prices in 2017, the Permian has clearly been where the majority of drilling activity is in the U.S., thanks in part to returns, Barnes said.

“Why the Permian? If you look at the analysis that shows breakeven economics based on where to spend the money, producers that have acreage in the Permian are getting the most bang for their buck,” he said.

The basin’s rig count has more than doubled since 2016 to more than 360 active rigs in June, according to Baker Hughes Inc.

At the same time, the U.S. Energy Information Administration projects a continuing increase of production in the basin this year toward 2.5 million barrels per day (MMbbl/d). Gas and NGL production also continue rising, thanks primarily to gassy wells in the booming Delaware side of the play.

There are numerous production forecasts for the Permian out there by various firms, Barnes noted, but “don’t focus on the numbers. They’re all a little bit different.” The upshot, he said, is that across the board, these projections all reveal the same danger of emerging short on takeaway capacity.

Constraints, but when?
“All of them indicate at some point, based on the production curves … additional takeaway capacity is going to be necessary,” he said. “And that’s where midstream companies like Magellan come into play to address those concerns for all the producers out there.”

Magellan forecasts a takeaway capacity constraint hitting the Permian by 2022 or 2023. Other conference speakers mentioned dates as early as fourth-quarter 2018.

However, midstream developers are already addressing the projection with announced projects significantly exceeding activity in the rest of the U.S., according to a recent report by Stratas Advisors.

Permian midstream developers announced 23 new projects, expansions or completions involving pipelines, terminals, docks, tanks and processing plants during the second quarter compared with 20 projects elsewhere, Stratas found.

“Our focus is increasing our takeaway capacity out of the Permian Basin through this Corpus Christi pipeline project,” Barnes said, noting the work on that project and the work expanding the BridgeTex Pipeline are some ways to increase capacity that Magellan has identified. “We’re very confident we’ll get to 450,000 [bbl/d] and we may even be able to get above 450,000 with fairly limited work that needs to be done.”

The new pipeline Magellan is developing to transport Permian crude to Corpus Christi will have multiple origin points in the Delaware and Midland basins, he said, as well as multiple delivery points in the Corpus Christi area.

“There’s been a lot of emphasis and push to go to Corpus Christi from a lot of producers to have that marine export capability,” he said.

Legal fences
As far as potential pushback from the public on the new pipeline, Barnes said he feels like Magellan has an advantage due to the company’s experience with previous pipeline projects, including its work on Saddlehorn, which carries crude from Colorado’s Denver-Julesburg Basin to the Cushing, Okla., storage and trading hub.

“I think the key to that is being proactive,” he said. “It’s definitely something that’s on our mind and I feel like we’re in a unique situation to take what we’ve learned on previous pipelines and bring it to the pipeline that we’re looking to construct down to Corpus Christi.”

The legal hurdles the Texas midstream must jump in the next few years are nearly as high as the sector’s challenge to add billions in new infrastructure, according to panelists on a law roundtable. Eminent domain may be the top concern, said Bruce Stanfill, a partner with Akerman LLP and a litigation specialist.

“This will be a major issue for the coming years in all parts of Texas,” Stanfill said. “It applies to the new pipelines, the [border] wall, the Houston-to-Dallas bullet train and more. There will be many contests of condemnation proceedings.”

Joining Stanfill in the discussion were Chris Smith, a partner with newly formed Smith Jolin LLP and previously a government and regulatory specialist with Thompson & Knight LLP, and Jeffery Muñoz, a partner with Latham & Watkins LLP specializing in energy M&A.

“Increasingly, landowners are using eminent domain law as a weapon,” Smith said.

Proceedings can be “procedural, not substantive” as landowners seek to block a project or to extract more favorable terms.

For pipelines, common-carrier status will be another major issue, Stanfill said, pointing out that only common carriers—systems serving multiple customers on a standard-tariff basis—enjoy eminent domain privileges. “It’s not enough to just check the box. They must show objective proof that the project will serve as a common-carrier pipeline. And the burden of proof is on the pipeline; you need to think about this ahead of time.”

Muñoz agreed, noting that a new common-carrier pipeline must be “completely used for the common good” and not a private development. That will require close examination of the relationship between the developer, third parties and joint ventures, he added. “You can’t do that early enough in the process.”

American made
The Trump administration’s changes to the regulatory environment will impact multiple legal questions in the sector, the panelists agreed. The mandate that new pipelines use only U.S.-made pipe “could be a big issue,” Muñoz cautioned.

“It looks great on paper to help get things built, but it is somewhat troublesome for the pipeline companies.”

Pipe shortages caused by high demand or the fact that U.S. steel mills don’t manufacture some sizes and pipe grades will create waiver applications.

“Implementation will drive this,” he added. “What kind of waivers will there be?”

“The new administration can’t do things by fiat. It will take a long time” to figure out how exceptions to the rule will be handled, Smith said.

In discussing another regulatory roadblock, Stanfill said Federal Aviation Administration stipulations sharply limiting the use of drones for industrial purposes “are a personal pet peeve. Drones are perfect for what you want to do, but you can’t use them” for pipeline rights-of-way patrols and site and equipment inspections.

Smith added, “As an environmental lawyer, I hate to see anything that is an improvement get locked up” by arbitrary regulations.

Operators often need to make “triage” decisions when multiple environmental questions come up as a construction project progresses, he said. “What’s the most important thing to look at?” It’s often possible to aggregate multiple small items into one single issue, which can speed the review process, Smith said.

Muñoz said, “The environment is a major part of every deal,” and operators should not take the issue lightly when planning projects.

Stanfill agreed, adding that too often, management takes a “just get the deal done” approach to keep a project moving. “That will bite you,” he cautioned.

Sabine, Colorado
Regarding the 2016 Sabine Oil & Gas Corp. bankruptcy, panelists said the final impact is yet to come. Saying that legal covenants between producers and midstream operators run with the land is not automatic, Muñoz cautioned.

“Just like common-carrier status, saying it doesn’t make it so.” As a result, an operator should “assume covenants do not run with the land and find other ways to protect [itself].”

“Draft your contracts carefully,” Stanfill cautioned, because legal requirements vary by state. “Texas law is not Oklahoma law. Oklahoma law is not New Mexico law.”

Worth watching is the potential legal fallout from the explosion this spring of a Colorado home near a leaking gas well, the panelists said. What is unusual about the case, according to Stanfill, is that “the house came to the pipes.”

Colorado law sets standards for new pipelines built near homes and businesses. However, in this case, the well and gathering lines had been in in place for many years before the residential development—the opposite situation—and legal requirements involving the developer are vague.

Belle of the ball

Gatherer and processor Lucid Energy Group LLC’s businesses in the Permian’s Midland and Delaware sub-basins are on separate trajectories. Lucid Energy has high growth potential in the glamorous Delaware and a mature, consolidating business in the still-charming—but aging—Midland, said Mike Latchem, president and CEO.

The privately held company backed by EnCap Flatrock Midstream operates in 12 counties and has more than 2 million acres dedicated to its systems by 80 customers. It can process 1 billion cubic feet per day (Bcf/d) and claims a network of 2,200 miles of pipelines.

The company is feverishly working on a new project in the northern Delaware, Latchem said. Unquestionably, acquisition and exploitation in the sub-basin has delivered Lucid’s recent growth, and these assets are the bright, shiny jewels in its portfolio.

“We entered the Midland Basin early and we were able to grow organically in the heydays of 2012 to 2014. Then, we turned and worked on converting a growth-oriented business into an optimized operating company.”

That transformation is a case study in the life cycle of a shale basin and how companies with fixed assets can adapt to a changing landscape. The first horizontal wells in the Midland were drilled on its eastern side in 2009; Lucid entered Texas’ Sterling, Mitchell, and Irion and Crockett counties in 2012.

“We were a little bit late to the game, but we were still there when the frenzied land grab was going on,” he said. “We were fortunate to get a lot of our organic infrastructure built when many people hadn’t fully bought into the Wolfcamp idea and the horizontal development was still in proof-of-concept stage.”

After the collapse in commodity prices, producers shifted their strategies. They narrowed their focus to economic drilling and rethought their land positions. By late 2014, producers were emphasizing development corridors in core-of-the-core counties and had pivoted to live with low commodity prices.

Fee pressure
Upstream operators honed in on how to make more profitable wells. This close-in examination was brought to bear on the infrastructure side as well. Producers began to micro-manage every aspect of development from power and roads to water resources to gathering, processing and compression. They now exert constant pressure on midstream firms to lower fees as much as possible.

But fees are only one piece of the puzzle, Latchem said. The quality of operations can be much more impactful for producers.

Lucid adapted by solving for the most efficient operations possible and optimizing netbacks. It turned its attention to factors that include offering modern deep-cut recovery systems, ensuring high facility run times and efficiently using fuel.

“We’ve been able to achieve greater than 99% mechanical availability on all of our plants, particularly in some of our newer, larger plants,” Latchem said. Near-perfect runtimes on compressors keep wellhead pressures low and gas moving. Another emphasis is on limiting flaring and keeping all hydrocarbons on pipe.

Access to markets is a key differentiator. “Where we’re taking our producers’ gas has the biggest impact on [net present value].” Recently, Lucid has been able to take advantage of the basis differentials between Houston and the Permian’s key Waha gas hub, for example.

“There’s a very delicate decision producers are making that is not just related to fees, but with aligning themselves with the right party in the Midland Basin. It’s more than just the fee. It’s more than just the netback on a contract. It is the netback with all things considered,” he said.

Going forward, Lucid sees a shrinking core in the Midland Basin. Operators are consolidating and greenfield opportunities in the midstream are limited. Without those, growth will necessarily come from acquisitions. Lucid is currently focused on acquiring strategic assets, with opportunities to integrate back-office business functions and consolidate systems.

“We're able to raise money; we're able to compete with MLPs in a consolidation play that’s not historically been available to a private-equity-backed company,” Latchem said. “I think we see the model changing, and the Midland Basin is going to be the beneficiary of that.”

The hub that isn’t

Not many oil and gas conference speakers illustrate their arguments with citations from Tolkien, but the peculiar nature of West Texas’ Waha hub inspired Midland-based gas trader Michael Banschbach’s approach to his presentation.

“One does not simply walk into Waha,” the president of Banschbach Consulting said, borrowing from the character Boromir in “The Lord of the Rings: Fellowship of the Ring.”

“It’s not a place that you feel that you’ve arrived at. It’s more a geographic area. It’s a confluence of pipelines that is a Texas area, maybe a three- or four-mile diameter area. But it’s much different than a specific place that you’re actually at,” he explained.

But it’s not exactly Mordor, Tolkien’s orc-populated land that is home to Mount Doom, either. It’s just that, unlike the industry-benchmark Henry Hub in Erath, La., it is not a true hub.

“Waha’s a little bit different,” Banschbach said. “There’s a lot of gas that interconnects from one pipeline to another. It never really does go through what we consider a hub. Actually, there are probably three or four hubs, if you want to look at it that way.”

Add the current capacity of 5.7 Bcf/d to 6 Bcf/d to that of the three new lines that will move gas to Mexico and this non-hub hub has 12 Bcf/d running through it, he said. But while there’s plenty of capacity, there is also plenty of unreserved space in those pipelines for prospective customers.

Multiple prices

The strange nature of Waha makes it difficult to get a handle on the price of gas, unlike hubs like Henry. “There are several different pricing points around Waha.” Among them are El Paso Permian, El Paso Waha, Oasis-Waha Pool and Waha, Banschbach said. “Each one is at a slightly different point. Some are upstream of the hub; some are downstream of the hub.”

That will change with an emerging Trans-Pecos Pipeline hub, “and all the smart marketing people will be involved.” The Energy Transfer Partners LP project heads south from the Permian and crosses the border at Presidio, Texas.

In addition to smart marketing, the extent of infrastructure in Mexico will determine the ultimate success of Waha as a staging point to deliver gas from the Delaware corridor in Culberson and Reeves counties, Texas. That, and pricing.

“All of the pipelines at Waha have—at their own expense, which is unheard of—interconnected with the Trans-Pecos Pipeline or will interconnect with the Trans-Pecos Pipeline to be able to ship gas to Mexico,” Banschbach said. “CFE [Comisión Federal de Electricidad], which is the Mexican utility, will own that. Energy Transfer will operate it.”

Typically, the price difference between Waha and the Houston Ship Channel is between 10 cents and 15 cents. In April, however, it widened considerably when CFE canceled a request for a proposal it had made in November for about 2 Bcf/d. Knocking that kind of demand out of the market battered the price at Waha.

That is why the journey that begins in a place reminiscent of Tolkien’s Middle Earth depends on what is happening in a destination: Mexico.

“Probably the biggest question is Mexico,” Banschbach said. “What is going to happen? What is the state of the infrastructure once you cross the border? Will they really get all these power plants built? Will they really use all this gas?

“The market reacted very quickly to the 2-Bcf/d deferment. Certainly, they’ll probably use that amount of gas at some point in time, but it’s deferred.”

The sentiment Banschbach gathered from operators involved was that “it’s going to be ugly in the next 18 to 24 months.”

Beware of bottlenecks

Greg Haas, director of integrated oil and gas for Stratas Advisors, detailed the export potential of Texas’ production. “The Permian is the driver of liquids supply growth.”

The firm has revised its production and pipeline-capacity numbers upward.

“Our top-down regional and full value-chain, integrated well-to-wheels analyses and forecasts show Permian-region operators are driving U.S. production growth, and those barrels are headed to places beyond Texas.”

However, surging Permian output must now compete with Bakken production arriving on the Gulf Coast following the June startup of the Dakota Access Pipeline as well as U.S. Strategic Petroleum Reserve sales that began in late February. The competition will tend to further weaken crude prices.

Unlike Vegas, the emphasis on exports means what’s happening in West Texas doesn’t stay in West Texas. The Permian Basin’s production boom will alter the world’s energy business at a fundamental level as its surging oil output goes overseas, said Ismael Hernandez, vice president of global business development for Buckeye Partners LP.

“When I go to conferences in London, Rio, Singapore and elsewhere, there are panel discussions that talk about the Permian Basin,” Hernandez said. “Make no mistake: This is a global phenomenon. I’m excited to be here.”

He emphasized a conference theme: The first problem Permian producers face is getting production out. “Bottlenecks for NGL will happen sooner,” he cautioned.

Crude takeaway capacity is expected to plateau under 3.5 MMbbl/d in early 2018 and stay at that level until the end of 2020 when additional pipeline capacity will go onstream, he said. Meanwhile, production could surge as high as 4.5 MMbbl/d by third-quarter 2020 according to some projections, although a number around 4 MMbbl/d is more likely.

Hernandez advised Midstream Texas attendees to keep an eye on Corpus Christi, which currently represents only 13% of Permian takeaway capacity but will be the endpoint for newly proposed pipelines. The Houston refining and petrochemical complex has the biggest share of current Permian capacity. Capacity headed to the Northeast is about 550 M bbl/d.

Capacity constraints will widen price differentials between the Midland crude hub and Cushing, Okla., but “greater access to Corpus Christi results in a narrower spread between Midland and Cushing,” Hernandez said. “Producers require options to maximize value.”

Corpus Christi assets
Buckeye has significant terminal capacity at Corpus Christi with storage, blending and splitting capabilities as well as deepwater dockage. It is expanding with its South Texas Gateway project, adding tankage and dockage, including the ability to handle deep-draft very large crude carriers.

The port is also the natural target for South Texas’ Eagle Ford production, he noted.

Increasingly, Permian crude will need to find export markets via the Gulf Coast, taking advantage of global options, Hernandez said.

The geographically diversified Buckeye also has terminal assets in the Caribbean and at New York Harbor. It holds a 50% interest in London-based VTTI BV, which has crude terminals in Europe, Asia, South America and Africa. “Buckeye possesses the ability to add value to each of its customers” because of its worldwide diversification, he said.

Hernandez has had a varied career in the energy business with a strong international bent. Before joining Buckeye, he was president of Sierra Pipeline LLC and was an executive with PMI Comercial Internacional, the international division of Mexico’s Pemex.

Hernandez concluded that the Permian is being closely watched in today’s rapidly changing oil market. “What happens will happen here first.”

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