A version of this story appears in the February 2018 edition of Oil and Gas Investor. Subscribe to the magazine here.

In the Haynesville Shale, a stellar natural gas play that fell out of favor when gas prices cratered, the rigs are back. More than 40 were drilling here recently, up from a low of just 12 during the downturn. The Haynesville rig count has been running neck and neck with that of the other most prolific U.S. gas resource, the Marcellus-Utica Shale in Appalachia.

It doesn’t hurt that Haynesville gas sells for only 10 or 15 cents below the Nymex-posted price, being the best-located gas play in the country. Marketed production is about 7 billion cubic feet a day (Bcf/d).

“The key question for 2018 and 2019 centers on how much running room the play has for these bigger wells. We view the Haynesville as the ideal asset to assume the swing producer role for Lower 48 natural gas,” Stratas Advisors said in a recent report.

The scope of the Haynesville’s prominence is told by looking at peak production rates recorded in the past: In 2012, the Barnett peaked at 5.1 Bcf/d and the Fayetteville at 2.8 Bcf/d, but the Haynesville peaked at about 10 Bcf/d in 2011. (The Marcellus-Utica has not peaked yet, experts say.)

The Haynesville has produced an average 6 Bcf/d in the past three years, but it will rise above 7 Bcf/d in 2018, according to the U.S. Energy Information Administration.

The forecast from Stratas Advisors is a bit more robust. “Haynesville production is expected to rise to about 7.5 Bcfe/d by year-end 2018, an increase of 11% from the 7.2 Bcfe/d reported for September 2017,” said analyst Whitney Gomila. “In recent operator presentations, internal rates of return [IRR] ranging from 75% to 100% can be seen at [$3], through the enhancements of completion techniques, longer laterals and increased EURs [enhanced ultimate recoveries].”

Haynesville production is being boosted by monster fracture jobs and extended-reach wells of 10,000 feet—after all, today’s technology is even better than when operators fracked the early wells between 2008 and 2012. For example, Comstock Resources Inc.’s older vintage wells drilled in the 2008 to 2012 time frame had EURs of 5 or 6 Bcf per well. When the company started drilling with much larger completions in 2015, it was estimating (and saw) 2.1 Bcf per 1,000 lateral feet. It has since upgraded that design, so from late 2016 going forward, it has been estimating (and seeing) 2.5 Bcf per 1,000 lateral feet for an EUR of up to 25 Bcf on a 10,000-foot well.

A Bernstein Research note said the average proppant load in the Haynesville has increased to 17 million pounds per well or 2,523 feet per lateral foot, the highest proppant load of the seven major plays it tracked on the FracFocus website, ahead of the Marcellus and Permian.

The Haynesville’s rising output, along with that of other plays, will likely keep a lid on natural gas prices for some time to come, analysts contend, despite the increasing gas exports from the U.S. Citing robust output from Appalachia, the Permian and Haynesville, Morgan Stanley analysts decreased their gas price forecasts for 2018 and 2019 in a recent report.

However, “We forecast 20% IRR breakevens are now comfortably below $3/MMBtu [million British thermal units],” at about $2.40, they said, situating the play between the Marcellus breakeven of $2.28 and the Utica of $2.83.

“The stronger gas prices over the past year, relative to the lows seen in 2016, support increased upstream activity in the [Haynesville-Bossier] Basin. Production has tracked our estimates through 2017, and our refreshed model indicates that dry gas production could grow by an incremental 0.5 Bcf/d by the end of 2018, and a comparable amount on average in 2019-20.”

Analyst JeanAnne Salisbury, in a Bernstein Research report, said the average Haynesville well has improved a lot over the past two years, with the average breakeven now $3/Mcf (full cycle). This is about 50 cents better than a year ago and competitive with the Marcellus-Utica on a fully loaded basis.

“This means that holding rigs flat at 45, we forecast growth to 6 Bcf/d by 2019 … and we believe this can occur even in a $2.50-price environment. This is bearish for gas prices,” she wrote.

Despite gas price conundrums, the Haynesville is attracting players as large as BP Lower 48 and many smaller, private players, several of whom may go public this year—if a larger company doesn’t snap them up first. Here’s a look at what some operators are forging ahead.

Haynesville Rescue

Comstock Resources Inc. chairman and CEO Jay Allison said he relied on the company’s Haynesville results to make it through the downturn, all the while improving the completion design. When commodity prices began to decline in late 2014, Allison pulled the reins in and said, “The downturn is coming, so which asset should we focus on to get through the deep valley?” The answer was the Haynesville.

“This is like the Monopoly board. If you’re looking at all the locations, EURs, pipeline takeaway and where gas demand is, then this is like the Park Place of gas,” he said. “We’re going to be a pure-play Haynesville company now.” Recently, Comstock put its Eagle Ford assets on the market to achieve that end.

During the downcycle, the company adopted a cautious, well-by-well plan, and by November 2016, it had completed a recapitalization. A second-lien note holder agreed to let Comstock pay in kind, using dollars to drill wells instead, so in 2017 the company drilled 16 net Haynesville wells and grew gas production by almost 40%.

Comstock Resources Inc. plans 22 Haynesville laterals of 10,000 feet this year, CEO Jay Allison said.

More recently, a new joint venture with USG Properties Haynesville LLC, an arm of $16-billion utility Next Era Inc., will allow the company to go even further. USG proposed leasing some Haynesville acreage and having Comstock deploy its technical skills. Comstock owns a 25% interest in these wells that rises to40% in 2018.

“It’s a super way for them to own more natural gas and for us to be able to drill,” Allison said. “Gulf Coast industrial demand is forecast to go up by 5 or 6 Bcf/d by 2020, and gas exports to Mexico are forecast to increase by 3 to 5 Bcf/d. LNG exports are now at 3, but if you look out to 2020, that could grow by 8 Bcf … so you’re going to see a lot of interest in the Haynesville—it can help meet that demand.”

Comstock entered the play early on, in 2008, by drilling deeper to the Haynesville and Bossier zones on existing conventional leases. From 2008 to 2015, it drilled 115 shorter-lateral Haynesville wells with EURs of 6 Bcf, all dry gas.

The Haynesville was the single-most important gas play in the U.S. until the Marcellus came along. As a result, north Louisiana’s midstream was nearly overbuilt, Allison said. Some 11 interstate pipelines go through the area. Many operators were thus burdened by pipeline commitments when the downturn came.

This year the company plans 26 gross wells and 22 of them will be 10,000-foot laterals. Comstock has three rigs and two frack crews under contract, with a 2018 budget of $170 million. One rig will drill its legacy acreage, and two will drill on acreage with USG. There are an estimated 850 locations all told, including 389 Bossier locations. “One of the best things we can do is develop the Bossier,” Allison said.

“We’re going to be busy for a while. The economics are really good in this play—we’ll be able to operate within cash flow yet grow our production another 30% in 2018, so it’s pretty miraculous. We know what the Tier 1 acreage is capable of doing, but since the play has matured, with better completions, what was once Tier 2 acreage or fringe acreage has become economic.”

Allison figures that for a 10,000-foot horizontal well costing $12.7 million, he can get 25 Bcf of gas, but those costs will come down now that operators are moving to pad drilling and starting to use local sand for proppant. In addition, he has budgeted for some refracks in 2018. The company has about 69,000 net acres in the play.

Asian Interest

Since 2013, there have been about 20 buyers in the Haynesville-Bossier area along the border of northeast Texas and north Louisiana, and with the exception of two, all have been private companies. Castleton Commodities International LLC (CCI) is one. This firm is backed by 25 family offices. About a year ago, its new subsidiary, Castleton Resources LLC, entered the play with a bang: a $1-billion acquisition of Anadarko Petroleum Corp.’s (NYSE: APC) acreage in East Texas.

“It’s remarkable what’s been happening in this play,” said Craig Jarchow, CEO of Castleton Resources. “The Haynesville is truly resurgent, and it’s because of the new completions. It’s industry know-how and persistence, paying off once again.”

Jarchow said the large transaction Castleton made in November 2016 was “an intentional way to use its financial and trading capabilities as a competitive advantage, to achieve economies of scale, and quite frankly, to make a statement,” given that many people were not familiar with the company. Last May, utility Tokyo Gas Co. Ltd. took a 30% equity stake in Castleton Resources itself rather than taking a working interest in wells via the joint-venture format as other international end-users have done. This is Tokyo Gas’ first equity investment in a U.S. upstream company.

“The beauty is in the alignment we have,” said Doug De Filippi, senior vice president of business development for Castleton. He covered Tokyo Gas and other Asian companies when previously a managing director at Goldman Sachs. “We’re very pleased to have such a blue chip investor, and one that is one of the biggest LNG importers in the world.”

Castleton has two rigs and one completion crew on its 163,000 net acres, all in the East Texas portion of the play. The Anadarko deal brought 2,700 producing wells (1,900 operated), with production of about 250 MMcf/d, with high liquids content. The Sabine Valley Pipeline system that was included is an added bonus that increases the return calculation, he said. In addition, behind-pipe zones such as the Travis Peak and Pettit offer icing on the cake.

“Another advantage we have is that we have mostly high net revenue interests here, so we are in a bit of an economic sweet spot,” he said.

Its $1-billion Haynesville deal was meant to make a statement, said Castleton Resources CEO Craig Jarchow.

Although much of the acquired production is from traditional, shallow Cotton Valley vertical wells, the production mix will change in 2018, Jarchow said. High-margin cash flow from these legacy wells will be used to fund the deeper horizontal Haynesville campaign. “We’re drilling almost exclusively Haynesville wells now, and production has been so encouraging that our Haynesville production will ramp up. We plan to have at least two rigs operating continuously through the year, while staying within cash flow.”

The company may add a third rig, he said. “It’s going extremely well. We’re starting to look at further acquisition opportunities within the same play, and we would look at north Louisiana also. But we do want to remain a pure-play company focused on the Ark-La-Tex region. I think focus is very important.”

A year after arriving in the Haynesville, Jarchow said the theme “is certainly these Gen 5 completions. The industry is drilling much longer laterals, and completions are much more intense than they were—some companies are using 3,500 pounds per foot of proppant, even 5,000 in some cases. Laterals are routinely 7,500 feet, but if land considerations allow, companies are testing 10,000 feet.”

Closer frack stage spacing has increased substantially, he added, and is working well on both sides of the Texas-Louisiana border.

“We’re very focused on cost control,” Jarchow said. “One thing that I think distinguishes us is that our operating costs are just 25 cents an Mcf and our G&A is on the order of 15 cents. One beautiful thing is that our East Texas basis relative to Henry Hub is fairly low, so we have high margins, some of the best in the industry.”

Behind-pipe reserves in the Cotton Valley, Travis Peak and Pettit add zip to the situation, he said, creating a multipay opportunity. But the Haynesville dwarfs any uphole completions or recompletions, he emphasized. The way forward is mostly about optimizing Haynesville completion designs.

"One of our strategies over time is to skate to where the puck will be," said Rockcliff Energy ll LLC president and CEO Alan Smith.

“There are areas we’d like to improve, such as trying new casing programs, different sources of proppant—all the things that would help get our costs down even more and get optimum production. For us, the pads’ locations will be dictated by where existing wells are and land considerations … but in theory, we could drill three wells to the north and three to the south.”

BP Lower 48

BP Plc (NYSE: BP) focuses on the Shelby Trough, a prolific area in Nacogdoches, San Augustine and Angelina counties near Lufkin in northeast Texas. The company refers to the area as SoHa. BP had four rigs running in 2017 but will hike that to six sometime this year, said Douglas Johnson, senior vice president of development for BP Lower 48’s East Business Unit, which includes the Haynesville. In 2016, it drilled three wells in SoHa, but in 2017, it brought online 17 wells, and that number will be even higher this year.

“We continue to drill some very good wells that generate success within our overall capital program,” he said. “It’s a very good project, and not just for the Lower 48 alone. BP is very excited about this and our path forward.

“In 2017, we escalated our activity in the Haynesville and liked the results we were getting; we demonstrated we could execute at scale. In 2018, we’ll expand from our existing footprint and go to full-scale development,” Johnson said.

Without divulging too much detail on completion design or well results, Johnson said that a metric like pounds of proppant per foot doesn’t necessarily tell the whole story.

“We are being very strategic in our approach here,” he said. “We first started drilling in 2016 to establish ourselves and establish our completion prowess. We understand the reservoir; where we are in Texas is deeper than on the Louisiana side. Here we’re at 14,000 feet and even deeper, but the pressure is also much higher, about 12,500 psi.”

Deeper, hotter wells create their own challenges even as they yield big flows. “Experimenting is not the word I’d use; I’d say continuous improvement instead,” Johnson said. “We purposely have collected a lot of data from every well. We’ll take core, and we log extensively, and we have 3-D as well, so we feel we have a pretty good handle on our lateral length and completion design.”

That length is usually 7,500 feet. At this stage, a single BP drill pad commonly has one Haynesville lateral and one Bossier lateral stacked above that, separated by 180 to 200 feet. BP isn’t pursuing any Cotton Valley pay at this time.

Also underpinning its well-level economics is BP’s large mineral interest and high net revenue interest here, which have allowed it to drill through the downturn, when other operators had to cut back.

“Prop-a-geddon”

A metric as important as rig count or lateral length is the often-compelling well results the Haynesville can yield. For that, turn to Chesapeake Energy Corp. (NYSE: CHK), which boasts some of the best IP rates in the basin, thanks to its latest monster frack designs and lessons learned from its leading position in other shale plays. In fact, 19 of its longest lateral wells are in the Haynesville, and it has done as many as 70 frack stages per well here.

In DeSoto Parish, La., its BSNR pad yielded 133 MMcf/d from four Haynesville wells; the least among them flowed 29 MMcf/d when turned to the sales line last September.

The bigger well flows are due to better understanding of the rock across the company’s entire footprint and making sure all completions are right-sized to the rock within any given play.

“We were expecting wells to average 10 or 15 MMcf a day before, but now the norm is more like 20 or 30. It’s really the technology that’s changed,” said Tim Beard, vice president of the Gulf Coast, Rockies and Haynesville for Chesapeake. “We talk about these bigger fracks, but our focus is not to pump exotic things or go bigger all the time—it’s to pump the right frack for the specific rock, throughout our portfolio.” The company uses a minimum of 3,000 pounds of proppant per lateral foot, but has tested as much as 5,000.

This operational fine-tuning has been achieved while adapting to gas price cycles: Last year it tried its first Haynesville refracks. It recently completed its first 10,000-foot lateral in the Bossier, in DeSoto Parish, which it thinks is the biggest Bossier well to date, flowing in excess of 30 MMcf/d on IP.

”Because the Bossier has more clay content, it should benefit even more than the Haynesville from tighter frack stage spacing. The industry is still trying to better understand the Bossier, but we’re encouraged by what we’ve seen,” Beard said. “We may drill another one in late 2018 or early 2019.”

Meanwhile, the company will deploy three rigs here this year (a rig can drill a well every 35 days) and one frack crew, hoping to complete at least 35 wells. It cites a breakeven gas price of $2.50/Mcf, mostly due to more effective fracks and other efficiencies. And, it will drill its first 15,000-foot Haynesville lateral, to be located in Caddo Parish north of where most people consider the sweet spot to be.

“The economics do get strained when gas goes below $3, so our team basically has reinvented the process,” said Frank Patterson, executive vice president of exploration and production.

“We have backed off some of the massive fracks … It’s a very good shale, but it’s complicated and it gets hotter on the southern end of our acreage. So, we took things that weren’t working at $3 and changed them, and a play that was kind of dead in the water has been revived. Now it gives a greater than 30% return.”

Along with technical experimentation, Chesapeake has been right-sizing its footprint here--selling $915 million of Haynesville assets in 2017, yet retaining net acres in the core.

“We’ve been coring up and paring down, and now we have close to 250,000 net acres,” Patterson said. “The bigger issue is, we came in early and captured a very large acreage position. We have only a third of that drilled, but it is all HBP, so even though we’ve been in development mode in the last three years, we still have two-thirds of our locations to go—and that doesn’t even count our Bossier potential.

“There was a sweet spot heavily drilled by us and the rest of the industry, but by changing our techniques we have basically changed the core. The renaissance in the Haynesville is that we’ve gone from a small core position that people thought was over-drilled, to something that’s expanded,” he said.

“These 15,000-foot laterals could open up further areas and make the wells more economic,” added Beard. “Everything’s gotten more efficient, and we’re expanding the commerciality of the play slightly to the north and to the west into Texas. We think the southern portion is already well-defined.”

How Chesapeake’s rigs are moved from location to location, and how its midstream facilities must adapt to bigger gas flows from high-pressure wells, are other factors that the company has addressed. The company also protects the reservoir by holding back wells and using a smaller, 14/64-inch choke, and it carefully monitors how wells respond as the pressure draws down.

Buyers’ Action

The increase in private company activity has been a big factor in the Haynesville during the downturn as larger publics drifted to oilier plays. Private operator interest can also be seen in recent M&A deals.

A private entity that closed on two deals last September is Rockcliff Energy II LLC, which is backed by Quantum Energy Partners and other institutional investors. It acquired $525 million of Haynesville assets in East Texas and northern Louisiana from Samson Resources II as the latter emerged from bankruptcy, and another package from an undisclosed seller. It later sold some of these assets to future LNG exporter Tellurian Inc. for $85 million, and to another, undisclosed private buyer. What is left? About 180,000 net acres in the Haynesville.

“One of our strategies over time is to skate to where the puck will be,” said president and CEO Alan Smith, “and we felt the Haynesville core in Louisiana was well on its way to being market priced, so we saw a good opportunity in Panola and Harrison counties, Texas, and we also have a chunk in Rusk. We do have some Cotton Valley acreage and Travis Peak production, but the main focus is Haynesville now.”

At press time the 2018 budget was still being finalized, but Rockcliff began activity last fall after the acquisition with two operated rigs in Panola County; Smith said he planned to pick up a third rig in January. The company started with a four-well pad right out of the gate. One rig will likely keep drilling Cotton Valley wells. The company’s footprint is substantially held by production with 1,100 operated wells, which was an important consideration when Smith was looking for the right acquisition.

Smith noted he’s seen enough from industry results to decide that Rockcliff will start with 7,500 laterals and bigger fracks. “We’ve certainly paid attention to what’s been going on out here, and we have a lot of data. But it will be driven by our internal engineering, our petrophysical data and well recovery information from previous wells that have been drilled around us.

“It is an iterative process, and once we start actually pumping and see what kind of results we get, we will fine-tune it. Where we are, the Haynesville is thicker than on the Louisiana side, so looking at spacing tests is going to be important. Optimizing frack lengths and design is the best opportunity.”

Rockcliff’s operations team is led by executives formerly with Petrohawk Energy Corp., who at the height were managing 15 or so rigs in this play, so Smith is confident Rockcliff will be able to execute. The play has been well-delineated on the Louisiana side but less so in East Texas. “Only a dozen or so wells have been drilled with the newest-generation fracks here, so that points to where things are headed and where the opportunity lies. It’s a bit early on the Texas side, but all the data looks very promising,” Smith said.

QEP’s Refrack Program

Many operators have tried, or say they will try this year, to re-enter and refracture older Haynesville wells by bringing to bear the latest-generation completion designs, using higher proppant concentrations. This will continue the progression for an “old” shale play that is now about 10 years on. Thousands of vintage wells could benefit from these enhanced stimulations.

QEP Resources Inc. (NYSE: QEP) is one of the leaders in refracturing here. Although in 2017 it pivoted to make a large Permian Basin crude oil acquisition and sell its Pinedale, Wyo., gas assets, it remains bullish on the Haynesville, where its net production averaged about 216.6 MMcfe/d during third-quarter 2017, a 63% increase over third-quarter 2016.

The company attributed the increase to the continued success of its refrack program. It refracked its first well in second-quarter 2016; it has now recompleted roughly 40. In third-quarter 2017, QEP refracked and returned to sales nine wellbores. These achieved average incremental production of 15.3 MMcfe/d per well over the original rate.

“Keep in mind that we divested Pinedale in September, but with our successful refrack program here, we expect to have replaced that production by the middle of 2018,” said chairman, president and CEO Chuck Stanley.

Current average gross QEP-operated Haynesville refrack costs are approximately $4.9 million per well. The company planned to refrack about 29 wells during 2017. (At press time, fourth-quarter results had not been released.)

In September 2017, thanks to these strong refrack results, QEP moved one operated rig into the Haynesville and started drilling new wells for the first time since 2012. At press time, it had turned to sales two new wells and was drilling its second 10,000-foot well. The stage count was 72, and the company is pumping 3,500 pounds of proppant per lateral foot.

“At first we thought 7,500-foot laterals would be optimal, but as the technology has evolved, we’re convinced that 10,000 feet is the way to go,” Stanley said. Each such well uses roughly 35 million pounds of locally sourced sand as proppant.

But it’s the refrack program that has been the real boost to QEP during the industry downturn. Since the program began in 2016, the company has increased its gross Haynesville production by nearly 215 MMcfe/d—without a drilling rig.

“Some of these refracked wells were initially drilled as far back as 2008, so we’re applying the latest generation completions now. Our selection criteria is to pick wells where we have high working interest and don’t need partner approvals,” said Chris Longwell, general manager of the Haynesville for QEP.

“In addition to improving the older wells, we’re using our refrack program to test optimal completion design for our new drilling program,” he said. “Refracking is less expensive than drilling a whole new well, yet it provides us with essentially a new well that bolsters our production profile and financial returns in the play. We first came up with this idea in our North Dakota operations, then successfully applied it in the Haynesville.”

Stanley likes the program because post-stimulation, the refracked wells flow at better rates than the original completions, and at pressures equal to the original well.

“We’re seeing 15 or 20 MMcf/d at 7,000 pounds psi,” he said. “Clearly, we’re contacting new rock that has never produced before. It’s like creating a ‘synthetic’ new well. We’re actually adding new reserves, not just accelerating recovery from existing reserves. We certainly plan to continue the program in the Haynesville and in other assets in our portfolio.

“Our Haynesville wasn’t making much gas two years ago, but to grow production like we have and get the cash flow it’s generating now—without drilling new wells—is remarkable.”

By mid-2018 its Haynesville refracks will replace the Pinedale gas production it sold last year, said chairman, president and CEO Chuck Stanley, QEP Resources Inc.

An added bonus is that QEP owns an established Haynesville midstream segment. Production in the system had declined when gas prices crashed and drilling slowed, but Stanley said he is glad he decided to keep the large-diameter system, which with a relatively small investment could double capacity and benefit from the increased activity in the play.

“We think the Haynesville is an incredibly responsive asset, growing cash flows and EBITDA associated with our capital investments in it. We’re excited about our future in the play.”

Leslie Haines can be reached at lhaines@hartenergy.com.