Changing Times

The oil and gas business continues evolving and Hart Energy’s popular DUG conference series is adapting in 2018 to meet the changing industry’s needs.

The first DUG Haynesville event, held before a packed house at the Shreveport, La., Convention Center, focused on an unconventional play that has enjoyed new life after several down years.

The Haynesville is “roaring back,” Tim Beard, vice president for Chesapeake Energy Corp., told conference attendees in his opening keynote address. Beard said technological breakthroughs, such as longer laterals and improved completion designs, have led Chesapeake to roughly 30% production growth in the Haynesville since 2016. He also pointed to an even brighter future in the play with the possibility for refracks and a recent “monster well” in the Bossier play.

The company was motivated to beef up activity in the region by a 2015 gas gathering agreement for its Haynesville assets with The Williams Cos. Inc., one of the midstream’s biggest players. That transaction included a commitment by Chesapeake to bring 140 wells online before the end of 2017. At the time, Chesapeake said it expected “significant production growth in the Haynesville Shale asset over the next two years.

“It’s not just a Chesapeake thing ... this is an industry thing,” Beard added of Haynesville activity. As an example, he pointed to recent rig count data gathered by Baker Hughes Inc., a GE company, which show a spike in activity.

In the past year, Haynesville producers have added nearly 50% more rigs. In mid-March, operators deployed 51 rigs in the play—compared with 37 a year earlier.

Production has also jumped with an early 2018 forecast of about 8 billion cubic feet per day (Bcf/d) of gas —a volume last seen in the region in 2013, according to the U.S. Energy Information Administration (EIA).

“There’s excitement in the basin again—the Haynesville is hot once again,” Beard told the crowd of more than 750 attendees.

Competing plays
It may be “a popular time to talk about the Haynesville again” as the unconventional play comes back to life—but its producers face plenty of competition, David Braziel, director of financial and fundamental analysis for RBN Energy, told attendees.

Braziel started his spotlight presentation with a broad examination of domestic production trends. The overall upticks are impressive, he noted.

“In the last 10 years, U.S. crude production has roughly doubled, from 5 million barrels per day (MMbbl/d) to 10 MMbbl/d as of November 2017,” he said. “There have been some hiccups, of course, like the oil price crash of 2014 and 2015 but production has rebounded.”

The biggest driver of that trend is the play “that is the center of everyone’s attention: the Permian,” Braziel added.

Crude producers’ success in West Texas and New Mexico “means that capital has poured into the basin,” Braziel said, on the hunch that the growth trend will continue. That Permian crude has a lot of associated natural gas, which has helped push U.S. natural gas up to 78 Bcf/d. Because of all that is associated gas, the Permian’s gas flow did not dwindle all that much even as gas prices slumped.

At the same time, the Marcellus and Utica plays’ gas output swelled by more than 10 times between 2009 and now, from 2 Bcf/d to 26 Bcf/d, “to where the primary limiting factor is getting that gas to market” via limited pipeline capacity, he added.

NGL output, to no one’s surprise, has soared to more than 4 MMbbl/d “to where it seems like a new gas processing plant is announced every other week,” he said.

“Unless something totally unexpected happens, we expect U.S. production to keep on growing,” he added. The futures markets indicate U.S. crude production could reach 13 MMbbl/d in five years, “and Lower 48 natural gas is headed toward 90 Bcf/d.”

Those massive flows will have to “duke it out” and find markets primarily within a Southeast/Gulf of Mexico box where the greatest demand exists, Braziel said. That region, extending from West Texas to Mississippi and from Oklahoma to the Gulf Coast, will be the site of virtually all demand growth—including new petrochemical plants, LNG and petroleum product terminals, and links to Mexico.

“Everyone’s building pipes to get in there,” he said of the region. Braziel added that “Rockies gas has only one way to go: east. Ruby [Pipeline] is full and there will be no more capacity” and that this is compounding the supply\demand challenge. Also, another barrier has emerged as the Mexican gas market has not grown as fast as many had expected.

The winner
So which basin will win?

“The short answer is the Permian,” the economist said, adding that LNG exports “are the only significant growth market” for the U.S., and the Permian likely has the best connections to Gulf Coast liquefaction capacity.

“How will we deal with all this uncertainty? What impact will it have on the Haynesville?” he asked. “To get the answer, we have to look at multiple hubs across the Southeast.” Braziel analyzed prospective gas flows into the region and how they will impact the Haynesville.

The North Louisiana/East Texas shale has the advantage of being close to markets, but limited pipeline capacity could hurt prices.

“In 2019, we get a breath of relief as Freeport, Cameron and Corpus LNG come online,” he said of Haynesville gas producers. The improvement could be temporary, however, as new pipeline capacity from the Permian links its strategic Waha gas hub to the Gulf Coast, providing new competition to Haynesville production, “and in 2021, north-south capacity out of the Haynesville maxes out.”

By 2022, new eastbound pipeline capacity out of the Permian will help Waha prices, “but the same may not be true of the Haynesville,” he cautioned.

Big players

Chesapeake is among the well-known players drilling up the Haynesville but the play has some nearly unknown producers that also have big plans.

Castleton Resources LLC is “the biggest East Texas producer you’ve never heard of” and its top-tier private partners will help it achieve success, according to its president and CEO.

Craig Jarchow, president and CEO of Houston-based Castleton, told attendees his firm enjoys “upside that we didn’t pay for” on its East Texas acreage—as well as the ready capital to exploit the resource.

Currently, Castleton produces 253 million cubic feet equivalent per day (MMcfe/d) of gas—72% natural gas—from 2,700 gross wells on 163,000 net acres. Proved reserves at year-end 2017 were 1.5 trillion cubic feet equivalent.

The company enjoys an edge because it owns and operates significant in-house midstream assets, Jarchow said. It has 786 miles of high- and low-pressure gathering pipelines, as well as water handling and gas condensate assets.

In addition to “overperformance” in the Haynesville—including a doubling of its location inventory—Castleton has opportunities to redevelop the conventional Cotton Valley play and other behind-the-pipe reserves, he said.

“If you want to know something about a company, the key is to find out something about their investors,” Jarchow said. Its owners, Castleton Commodities International LLC (CCI) and Tokyo Gas, are major players in the worldwide energy business. CCI, a major international commodities trader, holds a 70% interest and Tokyo Gas has the balance.

“Castleton is the former Louis Dreyfus [Energy],” he added, which was taken private in 2012 by a group of 25 “blue chip family offices. … It’s long-term, private capital.” Castleton is “trading on virtually every gas pipeline in North America,” Jarchow said.

For its part, Tokyo Gas “is one of the biggest players in LNG and the biggest gas utility in Japan,” he said, noting the firm imports an average LNG equivalent of 1.8 Bcf/d. It has investments in the Cameron and Cove Point LNG projects, as well as interests in Eagle Ford producers—and Castleton Resources.

Private players
“We think we have a real advantage. We think this is the future, not only in the Haynesville but in upstream oil and gas,” he said of the firm’s private investors. He noted there are multiple giant firms that have never gone public, including energy-focused Koch Industries and Hunt Oil; Cargill in food, drink and tobacco; and power-generator Tenaska.

“Why is that? It’s because there’s just a ton of private capital out there and you can grow a company to scale. That’s what we’re doing in the upstream space,” Jarchow added, at a time when the public capital markets have been essentially closed to oil and gas producers.

“Our source of equity is open,” he said. “Access to material, long-dated private capital is no longer a hindrance to building a large independent. Indeed, with the public equity markets closed to upstream companies, access to this capital is an advantage.”

He noted there has been a fundamental change in the New York Stock Exchange (NYSE) and other public markets in recent years as investors have moved to mutual funds, exchange traded funds and other investment vehicles. Program and automate trades comprise the bulk of daily volume. Jarchow estimated that only 10% of the daily volume on the NYSE now comes from active analysts and investors who do research, meet with firms and pick stocks.

“You have to be really big to get their attention,” he added.

The strong private-equity backing enabled Castleton to acquire the Carthage acreage formerly held by Anadarko Petroleum Corp. in 2016 for $1 billion through a bank syndicate. “We had $1 billion show up for a $560 million borrowing base, so we were 85% oversubscribed,” he noted.

DUG Executive

A week later, Hart Energy’s first DUG Executive conference opened in Houston to another full house at the Hilton Americas Hotel. Its agenda sought to answer a basic question: What’s next for the oil and gas business?

Maynard Holt, CEO of Tudor, Pickering, Holt & Co. (TPH), talked oil prices in his opening keynote. But it was Holt’s remarks on technology that set the tone for the outsized role tech now plays in tight oil and gas development.

“This sector\business\industry has obviously been doing some incredible innovation for a long time,” Holt said in his presentation. “The latest innovation has everything to do with returns and cost.”

What has changed is how much the industry is talking about it.

E&P leaders gathered at DUG Executive from multiple unconventional fiefdoms in the Eagle Ford, Permian, Midcontinent and Appalachia. But all of them talked technology—though not always in glowing terms. They talked big data, manufacturing models and the industry’s well-established spycraft: largely keeping an eye what their neighbors do.

Holt said that companies are increasingly preaching tech after a few companies began promoting their own advances to show that “not every company is made the same.

Once one or two companies started doing it, then everybody needed to start doing it” .

The TPH CEO said he sees parallels between the recent trajectory of U.S. E&Ps—an uncomfortably wild ride in the markets—and the early trials Silicon Valley endured.

The tech rush
“From 2008, the spring of the Haynesville Shale, through to Thanksgiving of 2014, energy had its massive rush, it had its huge run,” he said. Technology companies, like their shale counterparts, also had a huge rush of interest—followed by collapse and reexamination of everything they did, Holt said.

It was only after many years that tech companies “reached heights greater than its original peak.”

Holt said E&Ps won’t be in the penalty box as long as tech companies, but the results may follow the same path.

“What I would like to offer you is, that is what’s going to happen in energy,” he said.

Throughout the day, private producers and large, public independents similarly wove technology into their remarks and presentations. Randy Foutch, chairman and CEO of Laredo Petroleum Inc., touted the company’s proprietary data and analytics.

Jacob Shumway, FourPoint Energy’s vice president of engineering, pulled back the curtain on the private Midcontinent player’s proprietary databases. FourPoint’s dataset includes 20,000 digital logs, 1,500 square miles of 3-D seismic and a completions database crammed with details on 2,867 wells and 20,274 stages.

What about results?

Others surmised that for all the tech talk, what ultimately matters to investors are results.

Chad Perkins, senior vice president of operations at Greylock Energy, a private Appalachia E&P, joked during his presentation that “it’s mandated that all speakers say they are investing in technology today.”

Still, Perkins said technology has its costs. He noted that consolidation in Appalachia has taken away autonomy from workers who should be the experts on their wells.

“As much as I also have to say the words ‘artificial intelligence,’ I would just like to see human intelligence come back to the oil field,” he said. “And see the men and women being empowered to think about what they’re doing and make a decision.”

Holt began the conference by making predictions on how technology and shale are coming together, partly because the tech world realized “there’s so much money to be made in the energy business, and they just hadn’t really focused on us.”

He noted how badly oil prognosticators missed futures prices, which warped dramatically from 2011 to 2014. Partly, that’s because the environments in which the predictions were made influenced the predictions.

Similar trends in the energy business are being shaped now that are a decade away from coming to pass. The role of wind and solar energy, for instance, are just as hard to predict as oil and gas prices four years in the future.

“You can’t jump ahead. You need to get on the technology train, get with the smartest minds, stick with the stuff that makes money and it will take you there,” he said.

But the potential, he said, is for the oil business “as we know it” to be even more profitable.

“Oil’s market share could be higher. We just have to come together and fend off debates about the industry that are not based in science, that are not rational,” he said, “because there are a lot of people who are depending on high-quality, reliable, inexpensive energy for their lives.”

Alpine High
John Christmann, president and CEO of Apache Corp. left little doubt about where his company’s focus is these days—the Permian Basin—in the event’s afternoon keynote. While he espoused the potential of international plays in the North Sea, Egypt and Suriname, he told an audience of top-level oil and gas executives that “the Permian is attracting the majority of our capital investment.”

That’s no surprise considering Apache’s big Alpine High discovery in 2016.

“We’ve got about a 65-to-70-mile long fairway, and we’ve got 6,000 feet of rock to deal with,” he said. The play is vertically stacked oil, as well as wet and dry gas, Christmann said. The company holds about 340,000 contiguous acres that it owns without any partners “for the most part.” Apache has also identified more than 5,000 locations.

Christmann touted the company’s “tremendous economies of scale” in the play. “It’s going to let us do some things with gas and midstream infrastructure that are going to be differential.”

He told the audience that Apache is strategically positioned over the next few years to deliver large quantities of gas and NGL to the Gulf Coast.

What makes Alpine High truly unique is its 1,600 feet of true source rock, he added. “The difference is this was laid out in a very quiet, tranquil marine environment. Sea level didn’t move much. It was just gradually rising and falling. It sets up an environment where you can do large-scale deposition that’s pretty uniform,” Christmann said.

Midstream challenge
Moving the midstream along is one of the keys for the whole basin, the CEO said, and Apache has been doing just that.

“It’s a greenfield fit-for-purpose system,” he added.

Construction of Alpine High’s midstream component started in November 2016. Christmann said Apache invested about $700 million building out midstream assets through year-end 2017. So far, the company has brought along more than 330 MMcf/d of processing capacity. The plan is to have 830 MMcf/d by year-end.

“We are working through lots of various options in terms of how we fund this off our balance sheet,” Christmann said.

Through year-end 2017, Apache had five central processing facilities in place.

“[The Permian] will drive profitable growth for many, many years to come,” he said. “We’re running a balanced program between both the Alpine High and our other Permian assets in the Midland and Delaware basins.”