Oil and Gas Investor Haynesville Spotlight: The Gas Export Play

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[Editor's note: A version of this story appears in the May 2021 issue of Oil and Gas Investor magazine. Subscribe to the magazine here.]

The Haynesville Shale is a steam roller: a remarkable gas resource delivering impressive single well economics amid high flow rates. From initial forays in the play in 2008 through full development to December 2020, about 5,700 wells have been drilled here, but the allure is by no means over. Producers, midstream companies and gas end users love the Haynesville.

It is the only U.S. natural gas play where activity has fully recovered its average rig count after the slowdowns seen everywhere in 2020. As of mid-March, 32 rigs were working on the Louisiana side of the play alone, eight each in DeSoto and Caddo parishes. (The resource-rich DeSoto accounts for about a third of total Haynesville production.)

Despite the fact that its rig count plunged last summer when gas at the Carthage, Texas, hub traded for only $1.77/MMBtu, production has held steady during the past 12 months, staying at or near its current number: In March, Haynesville output averaged about 12.8 Bcf/d. (Total U.S. production was about 90.7 Bcf/d.)

Some 48 to 50 rigs have been operating between the Texas and Pelican State’s sides of the play, so the pace of drilling in the Haynesville exceeds its pre-pandemic, first-quarter 2020 level, Enverus said in late March.

Most of the wells average 11 million cubic feet a day (MMcf/d) initially, according to the Energy Information Administration (EIA), although it is not uncommon to see higher IPs of 20 MMcf/d or more. EURs are at least 2 Bcf per thousand feet of lateral. One of the biggest players, Comstock Resources Inc., said its “worst” wells drilled in fourth-quarter 2020 IPed at 18 MMcf/d gross; the best, in Bienville Parish, tested 33 MMcf/d.

“According to S&P Global Platts Analytics, Haynesville gas production could grow by more than 15% from current levels by fourth-quarter 2021. It’s also the most likely candidate to lead North America’s shale basins in overall volume growth this year, outperforming even the Permian,” said the EIA.

If the rig count reaches 50 and stays there, according to Simmons & Co. senior analyst Kashy Harrison, production could grow by 0.8 Bcf/d in 2021 to 2022. He bases this on listening to fourth-quarter conference calls of several Haynesville public producers. However, some 55% of the privately operated gas rigs in the U.S. are in the Haynesville (about 30% are in Appalachia). In any case, production goals are achievable here, which is why the Haynesville remains the second-most active play in the U.S. after the Permian. Its rig count lately is trending higher than the Marcellus or the Eagle Ford. It reached a 12-month high of nearly 50 rigs in March, a healthy chunk out of 92 gas-directed rigs throughout the U.S.

Producers can move their gas from the Perryville, La., hub to the Gulf Coast for 20 cents to 25 cents per Mcf, give or take, which is much less expensive than the long-haul pipes moving gas from the Permian Basin or the Northeast.

Additional midstream capacity is on track. On March 30, Midcoast Energy LLC brought its CJ Express online, further increasing takeaway to Gulf Coast demand centers by approximately 1 Bcf/d. “The expansion will increase gathering capabilities in the high-growth Shelby Trough area [in East Texas],” the company said. CJ Express is anchored by long-term transportation agreements with two creditworthy shippers, including sending gas to Golden Pass LNG.

The mantra

“The play is pretty much defined, and we’ve realized many of the technical gains from past experiences. And you’ve heard the mantra: It’s close to the coast,” said Doug Krenek, CEO, Sabine Oil & Gas Corp., which focuses on the Texas side of the play and has three rigs working there now.

The company’s production is about 350 MMcf/d, but “we’re trying to get to half a B, net, and then go into maintenance mode” he said. Sabine will drill close to 30 wells this year, about two-thirds in the Haynesville and one third in Cotton Valley, in Panola, Rusk, Leon and Harrison counties, Texas.

According to Enverus, the average well in the core of the Haynesville makes a 31% rate of return—if the price of gas on Nymex is $2.75/MMBtu. (It was bouncing around between $2.50 and $2.60 in March.) This is the highest return of any of the North American gas plays, the firm said.

“As of March 2021, operators in there are clearing an average 15% return on wellhead production, based on a half-cycle, post-tax analysis,” said Platts Analytics. “While those gains fall short of the 25% to 35% return earned by producers in Permian, they still rank among the highest in North America for a dry gas basin—outperforming Marcellus and Utica IRRs, currently estimated around 8% to 10%.”

The play’s breakeven varies by operator and location, but it’s now around $2.50/MMBtu, according to a report from S&P Global Platts Analytics. That’s good news, since analysts see gas prices rising through this year. Morgan Stanley recently said it is modeling Henry Hub to rise from $2.68 in first-quarter 2021 to $3 by yearend, averaging $2.65 in 2022. KeyBanc Capital Markets Inc.’s analyst Leo Mariani said in a report on gas macros that he foresees $2.60 gas this year and next year.

He also gave a shout-out to the Haynesville. “We expect to see 2% to 4% U.S. gas production growth in 2021 on an exit-to-exit basis due to growth in associated gas production from oil producers, reductions in flaring and increased activity in the Haynesville Shale.”

A premier play

“It’s the premier natural gas play in the Lower 48,” said Frank Tsuru, CEO of Indigo Natural Resources LLC, which produces about 1 Bcfe/d net from the play and 1.4 Bcfe gross.

Indigo is currently flowing 900 MMcf/d directly to Gillis, near Lake Charles, La., through DTE’s LEAP system (which was built by a sister company of Indigo, then sold to DTE). It has gas sales contracts with LNG producers at attractive Henry Hub-based pricing. The 150-mile, 36-inch pipeline was completed in July 2020, adding another plus to the play.

“The Haynesville has shown great resilience. It didn’t lose nearly as many rigs in percentage terms as other basins did last year. Our margins are greater, and some of these wells are prolific as heck. This basin shows great returns,” he told Investor.

Other long-time observers would agree.

“I’ve been working in this area for over 20 years, and the resilience of this play is amazing. Activity snapped back to pre-COVID levels faster than any other basin,” said Fritz Brinkman, CEO of Align Midstream Partners LLC.

Align operates about 300 miles of pipeline in eight counties in East Texas, most in Angelina and Panola counties, where its throughput volumes have been increasing, with more wells due to come on this fall as drilled by Aethon Energy Management LLC, one of the most active E&Ps in the area, which is running nine rigs currently.

Last year in mid-June during the pandemic and downturn, Align completed its 30-mile TOPS Pipeline, a joint venture with Sabine Oil & Gas in the prolific Carthage area in East Texas.

A production star

The EIA said in March that the average Haynesville rig would add 11.4 MMcf/d of new production. Multiply that by 50 rigs and you get the scope of things. IPs vary depending partly on an operator’s goals and takeaway situation, well location and completion process. Some companies pull their wells aggressively in order to provide the Street with a big headline number and to move net present value forward.

The Haynesville’s resource potential remains quite abundant, which keeps E&Ps interested—along with some end users such as Osaka Gas USA, which owns Sabine, for example.

The Japanese company’s U.S. subsidiary thus owns producing assets and interests in LNG facilities as well. This bolsters Sabine’s activity, although the drilling is funded mostly out of cash flow. Krenek said Sabine should go cash flow positive next year.

Many of the operators in the play, whether in Texas or Louisiana, are privately held, which gives them a different mindset than some of the big public companies, he noted. “We can look at everything in a long-term way now that Osaka owns us. A lot of your decision-making depends on who owns you and how you plan your drilling schedule,” Krenek said. “This helps us in our agreements for gathering, services, marketing and so on.”

On the company’s 248,000 net acres, EURs on Sabine’s best acreage are 2.25 Bcf to 3 Bcf per 1,000 ft of lateral.

The learning curve on completions is fairly well optimized, he said, so the current focus is on nailing down the perfect parent-child well spacing, although for best results, well spacing doesn’t concern Krenek as much as getting the development timing right.

Current pads have three or four wells, but “super pads” with up to 10 wells will be coming soon, he said, but upfront comes the logistics of getting facilities and saltwater handling equipment in order first.

“If you can eliminate the parent-child problem and take a long-term view, that is good. We call it the ‘mow-down,’ where you try to mow it all down at once, or at least, get back into an area in less than a year after development has started. We also alternate landing zones, which helps,” Krenek explained.

The deeper Louisiana play

Indigo is drilling in the far southeastern part of its position in DeSoto Parish, where extreme bottomhole temperatures and pressure are challenges, yet that also yields some big wells, making 2.5 Bcf to 2.7 Bcf per thousand ft of lateral. “We’ve seen some of the best wells we’ve ever drilled,” CEO Tsuru said.

The company plans to deploy between five and six rigs throughout this year and one or two frac crews, to drill wells with an average lateral length of 7,000 ft. Production growth will be modest, from flat to 5%, echoing the pledge for capital discipline made by other E&P companies, he added.

“We’ve seen a reduction in service costs and well performance coming up, so we’re pleased with the economics. We are the only operator in this deep, hot part of the Haynesville in this area of Louisiana.” (There are equivalent areas in East Texas’ Shelby Trough area. The pay gets deeper as you go southwest to the Shelby Trough, so it’s more expensive to operate. BP Plc and Exxon Mobil Corp. are drilling there.)

“It’s a different type of well there with greater EURs, although the other areas are good. We’ll allocate two-thirds of our capital budget to this southeast area, whereas last year it was about 50%, so we are ramping up,” Tsuru said. The company has at least 20 years of drilling inventory in its Haynesville and Bossier positions, on some 280,000 net effective acres in Louisiana.

LNG is calling

The Haynesville is more than just another pretty face in the natural gas world, for it is the go-to source of feed gas for delivery to the Gulf Coast LNG export corridor. This is the advantage producers in the play bank on.

In January, Morgan Stanley called for an LNG global supply shortfall quite possibly emerging by 2023 amid growing global demand. A 50% price decline in 2019 was made worse by the collapse in oil and gas demand in first-half 2020, but the firm now says a multiyear upcycle has begun as demand for LNG is growing twice as fast as supply.

S&P Global Platts expects U.S. exports to reach more than 11 Bcf/d this year. Exports already hit a record send out in March of 6.64 MMtpa (million tons per annum), and the future looks bright, as more export capacity is ramping up. Cheniere Energy Inc.’s third train at its Corpus Christi terminal just came online, for example.

The only bad news is that the amount of feed gas needed on the Gulf Coast can vary wildly, as it depends heavily on global LNG demand and pricing. That market just suffered through an unusually volatile trailing 12 months.

Exports from the U.S. had more than doubled in 2019 to 7.8 Bcf/d and just preCOVID-19, they had reached 8.5 Bcf/d in February 2020. But then they fell off the cliff, plunging all the way down to 3.4 Bcf/d last summer. In total, several buyers canceled more than 95 cargoes, according to Energy Ventures Analysis Inc., based in Arlington, Va., which conducted an LNG study for the Natural Gas Supply Association.

But the recovery has kicked in now. In March 2021, that feed gas demand attained a record high of almost 12 Bcf/d. As IHS Markit’s Bob Fryklund has said, the Haynesville is an export play above all else. In early April, feed gas demand from the Gulf Coast’s four LNG terminals, including Sabine Pass, Cameron, Freeport and Corpus Christi, was near record-high levels averaging about 10.8 Bcf/d, according to Platts.

Two important end users, Tellurian Inc. and Osaka Gas USA, own producing wells in the Louisiana side of the play. Tellurian’s production is about 46 MMcf/d from the 71 producing wells it owns on its 10,000 net acres. Revenue from these has been used to help pay down loans. The company’s Driftwood LNG export facility in Calcasieu Parish is fully permitted and shovel ready. Osaka Gas, which has U.S. LNG interests, acquired the rest of privately held Sabine it didn’t already own last year.

Midstream outlook

The Haynesville will continue to do well this year if gas prices hold, and because several additional large gathering lines and pipelines are coming on this year and next to move more gas to petrochemical plants and LNG export terminals. According to BTU Analytics, 4 Bcf/d of new pipeline capacity will come online this year and through 2022.

Align Midstream is working on two new projects now: 30 miles of trunkline and another of 10 miles of trunkline and gathering for four well pads. CEO Brinkman said he expects an additional 300 MMcf/d to come on, based on recent average IPs and operator estimates. He’s also talking with potential partners about another project that would move even more gas to the Gulf Coast and, if completed, would be a game changer for Align, as it would directly access the industrial and LNG market demand there.

“We keep opportunities in mind every day,” CEO Brinkman said,” and we’re constantly thinking about how to serve our producer customers.”

Watching the E&P customer-front, Brinkman said he has seen an evolving landscape during the past several years. “A lot of PE-backed E&P companies have moved in, and we’re fortunate that they are well-hedged and able to keep drilling,” he said. “The breakevens in core areas are closer to $2 now, where several years ago I remember it used to be $3 or $3.50. You have six or seven very strong producers here who are well-positioned and have strong growth opportunities with several highly economic well locations.”

When Energy Transfer Partners announced it would buy Enable Midstream Partners for $7.2 billion, it cited its desire to expand its presence in the Haynesville as one of the reasons. It will take over Enable’s critical Perryville gas hub in northern Louisiana. Enable planned the Gulf Run pipeline, which will run 135 miles from the play to the Gulf Coast, with capacity of 1.1 Bcf/d. It was expected to get final Federal Energy Regulatory Commission approval this year and start up by fourth-quarter 2022.

More infrastructure will be needed, as operators continue to see initial flow rates much higher than the 11.4 MMcf/d posited by the EIA. Newly public Vine Energy Inc. recently reported results from a two-well pad in Section 9 of Red River-Bull Canyon Field in DeSoto Parish. Aggregate production was more than 52 MMcf/d. On the Louisiana side, IPs of 20 MMcf/d to 28 MMcf/d are reported as the good rock trends toward deeper depths and hot, higher-pressure conditions downhole.

On April 1, Midcoast Energy LLC’s expansion of the CJ Express line went into service, adding 1 Bcf/d. The firm, a portfolio company of ArcLight Capital Partners LLC, has a secure transportation deal and gas purchase and sale agreement with the Golden Pass LNG terminal in Sabine Pass, La., which is owned by Exxon Mobil and Qatar Petroleum. It will eventually process 16 MMtpa of LNG.

DTE Midstream’s LEAP system (Louisiana Energy Access Project) provides 1.2 Bcf/d of gathering lines from the Haynesville to the Gillis Hub in Calcasieu Parish near Lake Charles.

A new lateral that will take 250 MMcf/d from Logansport to Enterprise Product Partners’ Acadian project, which will help Comstock Resources, which is a major shipper on the 1 Bcf/d Acadian extension that goes in service in fourth-quarter 2021.

Brinkman said it is “fun to see the collaboration between producers” that enables sharing of technology and longer lateral lengths in these horizontal wells. “With all the activity and with gas prices getting stronger, I wouldn’t be surprised if the Haynesville gets to 15 or 16 Bcf/d here soon. It’s just such a huge resource.”