H&P floor hands Justin Hill (left) and Matthew Hertenstein put a slip in place to hold the drilling pipe on

Headrick 14-11 HC No. 2-AH well at Comstock Resources' gas drilling operations in the Haynesville Shale.

Photo by Tom Fox.

The morning after the Super Bowl, Jay Allison remarked upon the New England Patriots’ comeback win. “I thought the game was going to be just horrible and then it became great. Like the Haynesville: It became horrible and now it’s great again.”

The chairman and CEO of Dallas-based Comstock Resources Inc. faced some daunting decisions in late 2014. Operating in the Eagle Ford, oil had already fallen from more than $100 during the summer to less than $75 before Thanksgiving. The OPEC-induced free-fall eventually found bottom at just under $27 in early 2016.

“The past couple of years were one of the worst oil crises in a generation,” Allison said. “It wiped out trillions of dollars in market value. It made most drilling prospects worthless no matter what basin you were in—or no matter what country you were in.”

He looked again at the company’s legacy dry-gas asset in northwestern Louisiana. The Haynesville Shale had gained disdain among investors when just a few years old. Announced in early 2008, estimates were that a short lat-eral could make up to 10 billion cubic feet (Bcf) of gas.

But gas slipped below $2 in April 2012. At some 12,000 feet of vertical depth and during an oil-price-driven boom in oilfield-service costs, the wells cost more than $10 million. The Haynesville's star faded. The rig count declined from 160 at the peak to 11 in early 2016.

Comstock has been drilling in northwestern Louisiana since it was formed in 1991. At the time, it was making verticals in the shallower Cotton Valley, Hosston and Travis Peak. In 2007, it drilled into the Haynesville as rumors thickened about Chesapeake Energy Corp. developing a new play out of the formation.

The company’s leasehold today that is prospective for Haynesville is 67,000 net acres. “We have a very large Tier 1 acreage inventory in the play,” Allison said. Its position has contiguous sections that allow laterals of up to 2 miles. Inventory is 700 locations. The acreage has been de-risked by some 125 pre-2013 wells.

“We’ve got a head start on a lot of the newer companies out there because of all of our in-house information,” Allison said. “Historically, we’ve had superior wells but, because it was dry gas, they didn’t have a lot of value.”

While gas has continued to average less than $3 per thousand cubic feet (Mcf) the past few years, the completion recipe and costs have changed. “In 2008, you had small jobs with cross-linked gel. We moved to 100% slickwater.

“Our proppant loading got larger and larger—from about 1,000 pounds per lateral foot in 2008 to 3,800 pounds now. We used resin-coated sand early on; we’ve moved to 100% white sand.

Frack intervals have doubled—from every 300 feet to 150 feet. The new formula provides 2.4 Bcf per 1,000 feet of lateral—thus that 10-Bcf-plus well from a one-section (about 4,750-foot) lateral. Lateral lengths are extending beyond a mile to 7,500 and 10,000 feet.

H&P derrick hand Daniel Wellborn goes through the process of weighing drilling mud from Comstock Resources'

Headrick 14-11 HC No. 2-AH well. Bottom right, H&P floorhands, including Justin Hill, make a drilling pipe connection on the well.

Photo by Tom Fox.

Downturn management

When Comstock went back to its Haynesville asset in early 2015, “we had ice on the ground,” Allison noted. The winter of 2015-16 was warm, though. Gas was $1.63 on Christmas Day. When turning back to developing its dry-gas asset in early 2015, “we were never thinking it would hit a 17-year low of $1.49 in March of 2016.”

Comstock underwent a capital restructuring. It exchanged 98% of its senior notes, totaling about $1.1 billion, for senior secured, warrants and a convertible second lien. An additional $237 million of debt had previously been exchanged for shares and $60 million.

It did a 1-for-5 reverse stock split and sold 49 Bcf of proved conventional gas reserves in South Texas for $28 million. In 2015, it had sold acreage in the Eaglebine play in Burleson County, Texas, for $164 million.

Among its first 11 (7.8 net) new Haynesville wells, its recipe drew upon its Eagle Ford experience, where it had made high-intensity completions on 190 extended laterals. “No one had drilled an extended lateral in the Haynesville using modern frack techniques,” Allison said.

“If the Haynesville was so good in 2007 into 2012, we thought it could be better now. We can extend the laterals, increase proppant loading per foot, increase stages.”

Expectations from the first new wells were for IPs of 20 million cubic feet per day (MMcf/d); they came on with an average of about 23 MMcf/d. “We thought EURs would be 12 to 15 Bcf. Comstock’s first 13 wells’ EURs were 16 Bcf.”

The cost of each averaged about $8.1 million. “We were elated.”

Of its roughly 700 operated locations, excluding acreage it recently entered as part of a joint venture (JV), 383 are Haynesville and 153 of those will have 7,500-foot or longer laterals. Among its 322 locations for the overlying Bossier, 192 will have extended-reach laterals. At $2.50 to $3 gas, they will generate a rate of return between 70% and 100%.

A typical completion on a 7,500-foot lateral has 50 stages, each with five clusters per stage—“every 30 feet, so 250 clusters per 7,500 feet,” he added.

“The design is still evolving. We’re seeing what other operators in the area are doing and we’ve participated in some of their wells as nonop.

“The reason the Haynesville gets better for us is that we are the low-cost producer. We have Tier 1 acreage: great geology, great inventory, no bottlenecks, very healthy netbacks. Our cash operating cost is less than 40 cents per Mcf, which is transportation.”

Transportation costs were a hurdle that even the best wells couldn’t overcome for some operators in the play; for these, long-term takeaway commitments grew to exceed $1 an Mcf. “We didn’t do that,” Allison said.

“That is why we are so profitable at a $2.50 to $3 gas price. A lot of others, if they weren’t so burdened by their firm transportation issues, their advantage would appear.”

‘We’re Haynesville’

Comstock estimates it has some 6 Tcfe of upside in the Haynesville and Bossier. It now has 18 modern Haynesville completions and 200 feet of the rock in the core. In the early days, these were drilled in the uppermost portion of the formation to not risk fracturing into the water-bearing, underlying Smackover.

“Technology has materially improved,” Allison said. “We’ve drilled a couple of wells in the lower portion of the Haynesville and we haven’t had any interference with the water or any communication with wells in the upper Haynesville. We believe there is a lot of potential for a staggered-lateral program.”

If it works, Comstock could drill eight wells per section with 600-foot spacing rather than six, adding 83 additional locations in its leasehold.

It picked up 3,600 net acres in DeSoto Parish last year in a swap with EOG Resources Inc., adding 39 Haynesville locations—33 of these extended-reach. To EOG, it gave some 2,500 net acres in Atascosa County, Texas, in the Eagle Ford Shale.

In January, it entered a JV with USG Properties Haynesville LLC, involving 3,315 net acres in western Caddo Parish. Comstock is the operator for a 12.5% working interest and bought another 12.5% at USG’s cost.

It will begin drilling it this month, bringing its rig count to three. USG and Comstock expect to continue to add acreage to the position.

Overall, Comstock’s capex budget is $168.5 million this year for 22 gross, 17.2 net, Haynesville wells. Its proved reserves grew 47% in 2016, net of deducting for a 15.7-billion cubic feet equivalent (Bcfe) paper loss due to lower oil and gas prices. In the Haynesville in particular, it added 429.1 Bcfe. This was on top of an add of 143.6 Bcfe in 2015.

Six of the newest Haynesville wells averaged an IP of 24 MMcf/d, all in DeSoto Parish and with 3,800 pounds of proppant per lateral foot, up from 2,800 on previous wells. The Pace James 5-8 #1 came on with 25 MMcf/d from a 7,593-foot lateral; Claybrook 15 #2 with 24 MMcf/d from 4,389 feet; and Halsey 14 #1 with 21 MMcf/d from 4,476 feet.

Chris Stevens, analyst for KeyBanc Capital Markets Inc., wrote of the Claybrook and Haley that “it is encouraging that the shorter-length laterals are also exhibiting IP rates of more than 20 MMcf/d.”

During the 2015-2016 downturn, Comstock issued $440 million of second-lien notes that convert to equity if shares trade at $12.32 or better for 15 consecutive days. “When that happens, our leverage ratio goes from 6.3x EBITDA to 3.3x,” Allison said. “It materially delevers us. In the interim, we try to stay within cash flow.

“To be able to hold our heads up high after these past couple of years, it’s nice. Not everybody has been so fortunate.” The producer has 72 MMcf/d of 2017 production hedged at $3.38 per million British thermal units (MMBtu).

“Do you have high returns in the Haynesville? We didn’t know in 2015,” he said. “The answer to that today is ‘yes.’ The enhanced-completion design has transformed the Haynesville. It’s one of North America’s highest-return basins for natural gas now.

“We’ve been in it since 2007 and we’re still in it. We’ve drilled on every section. It’s all HBP (held by production). We didn’t buy our way in. It’s a very strong foundation. Even with the nominal drilling we did in 2016, we increased our proved reserves 47%. With our capex budget this year, we can grow our production by 40%.

“We’re Haynesville and we think it will continue to get better.”

Haynesville heaven

Entering 2014, Goodrich Petroleum Corp.’s assets were in the Eagle Ford, Haynesville and Tuscaloosa Marine Shale. At one time, while it was aggressively pursuing the TMS, it was believed that Goodrich would divest its Haynesville position.

But, it didn’t sell the Haynesville and this “clearly worked out for the better,” said Rob Turnham, president and COO. The probem with the Haynesville wasn’t the rock; it was Goodrich’s transportation cost. Through Chapter 11 last year, the court rejected the company’s transportation agreement. Today, it still has Haynesville as well as its Eagle Ford and TMS assets.

“It’s like that old country song: Be thankful for unanswered prayers,” Turnham said.

“We were able to eliminate $400 million of debt and a couple hundred million of preferred and we still have all of our assets. None of us liked what we had to do, but it sure helped the situation going forward.”

In the early days of the play, gathering was needed as well as big pipe to take on the expected volumes. Basis and transportation grew to cost Goodrich on its nonop property as much as $1.50/Mcf. Some other producers experienced the same.

That has declined to Henry Hub minus between 37 and 75 cents. “We saved about a dollar per Mcf on average of throughput charges,” he said.

Going into the gas-price downturn that began in the spring of 2012, Goodrich had 85 vintage Haynesville wells—each with about 4,600-foot laterals, 1,100 pounds of proppant per foot and in stage intervals between 250 and 400 feet. “And we were still getting about 1.2 Bcf per 1,000 feet. It’s because the rock was good.”

Goodrich recently participated in two Chesapeake-operated tests of 3,000 and 5,200 pounds per foot.

“It’s just a game-changer,” Turnham said. “It’s not only proppant per foot; it’s also tightening that frack interval down to 200 feet or 150. You’re getting better near-wellbore stimulation. The wells before were leaving gas-in-place behind; they were just under-stimulated.”

The two wells in which Goodrich participated—the ROTC 1H and 2H, both in Caddo Parish, La.—had a combined peak 24-hour rate of 72 MMcf. The 1H made a Bcf in 25 days; the 2H, just shy of that. Their combined production in a little more than two months at press time was more than 4 Bcf.

They were still producing some 61.4 MMcf/d, combined. As for EUR, the wells are exceeding Goodrich’s internal high-case curve of 2.5 Bcf per 1,000 feet of lateral.

“They are massive wells,” Turnham said. Goodrich has a 17.4% working interest in each.

Chesapeake reported on the ROTC 1H and two others in late February: “Delivering monster IPs.” ROTC 1H came on with 40 MMcf/d from a 10,000-foot lateral; it underwent a frack of 5,200 pounds per foot. Its CA 1H, also in Caddo Parish, came on with 38 MMcf/d from 10,000 feet and 3,000 pounds per foot. In northern Sabine Parish, Nabors 2H came on with 19 MMcf/d from 5,200 feet with 5,000 pounds per foot.

Coiled tubing operations by Redback Coil Tubing are reflected at dawn on Comstock Resources gas drilling operations on Headrick 14-23 HC No. 1-AH well in DeSoto Parish.

















Near-wellbore stimulation

Goodrich’s 2017 capex budget is between $40- and $50 million, all dedicated to the Haynesville for between nine and 13 gross wells (three to five net). It was drilling its operated Wurtsbaugh 26H-1 in northern DeSoto Parish at press time for a 4,600-foot lateral that is to be
completed with between 4,000 and 5,000 pounds of proppant per foot. It plans to drill its Wurtsbaugh 25- 24H-2 next with a 10,000-foot lateral.

With some 24,000 net acres prospective for Haynesville, 16,000 of these are in North Louisiana for 235 gross locations, 41% average working interest, and 8,000 are in East Texas for 123 gross locations. It also has 123 gross Bossier locations with a 33% average working interest.

All of its leasehold is HBP. Goodrich operates about 40%. Chesapeake operates a majority of the balance. Privately held Indigo Resources LLC now operates some by virtue of a recent acquisition from Chesapeake.

What is the maximum amount of proppant per foot that is worthwhile? Turnham said, “I’m not sure if it goes higher from here, although our 5,000-pound-per-foot well is just outstanding.

“As long as sand prices are low and frack equipment is fairly cheap, pumping the maximum amount of proppant makes a lot of sense so far. There is no question the 5,000-pound-per-foot well is better than the 3,000, but the 3,000 is exceeding our highest type curve as well.”

In its examination of decline curves in the play, he said, “the one common theme is that more proppant makes better wells.” The proppant in the modern jobs is white sand and primarily 40-70, “although I think brown sand is going to work also.” Jobs are started with 100 mesh sand.

Early Haynesville completions were with gel. “We thought you wanted to get frack wing length away from the wellbore to pull more gas in. But what we’ve found from a number of different basins is that what you really want is better near-wellbore stimulation.

“You want to create complex fracturing near the wellbore that allows you to recover a higher percentage of gas near the wellbore. Slickwater creates complexity, so the higher the slickwater component, the more that spider web of fractures is created.

We’re not needing to transport the proppant way out into the formation. In reality, that was closing up on us anyway. We just want to stimulate better near the wellbore.”
Stacking and staggering wells within the formation—landing high and low—does make sense for more drainage, he added. For now, however, Goodrich has modeled six wells per unit that are 880 feet between laterals, landing in the deeper half within 40 feet of the bottom where porosity is between 12% and more than 15%.

“We feel like a lot of your fracks grow up and there’s a better signature down below,” Turnham said. “It drills better and we get better stimulation by landing lower.” With proper spacing, the bigger completion job may drain more of the 200- to 250-foot column vs. landing both high and low with 660-foot spacing.

“We think it’s worth testing and we think operators are currently testing that, but we need to see a comparison before we do that.”

1,000 trucks of sand

Because of high transportation costs in the Haynesville, Goodrich wouldn’t have gotten much for its acreage there had it been sold before its Chapter 11 process. Instead, it sold its Eagle Ford position down to 14,000 undeveloped acres. “At some point, it probably makes sense to sell that block, while we continue to focus on the Haynesville,” Turnham said.

As oil prices recover, it may return to the TMS where it was zeroing in on best drilling practices. The most proppant it pumped there was 2,200 pounds per foot. The interval is about 220 feet thick.

“But we need higher oil prices to justify going back there—particularly when you look at the rates of return we are generating in the Haynesville. Right now, the Haynesville’s rates of return are far more superior.”

Of its 235 gross North Louisiana locations, about 100 are net. Production so far is suggesting 800 to 900 Bcf of reserve exposure; adding in its East Texas leasehold takes that to more than 1 Tcf.

At the pace of nine to 13 gross wells this year, it has a 15- to 20-year drilling inventory. In terms of adding leasehold, Goodrich will look at it, but its budget is devoted to generating immediate profit. “We don’t want to spend a lot of cash and use up our liquidity on buying more acreage at market prices.

“We’re sitting here with the ability to generate up to 100% rates of return at current well costs with these longer laterals and bigger completions. It’s a huge step change in the economics of this play.”

In addition, Goodrich’s lease operating expense is 5 cents an Mcf. The state waives severance tax on new wells for two years or until payout, whichever is earlier. The wells produce 100% dry gas, so there is no formation-water-disposal cost.

The high-pressure nature of the Haynesville means gas compression isn’t needed. Turnham said, “You need a gauger to go by and you need insurance, but it’s just light maintenance work.”

He doesn’t expect this renewed Haynesville drilling and the bigger wells—Chesapeake has talked about its higher-proppant wells making up to 9 Bcf in a year—will collapse gas prices again. “Whether it’s 5 Bcf or 9 Bcf, that’s a lot of gas in Year 1. The basin is going to grow, but in a measured way.

“There are fewer operators—maybe 15 of us—and many of them probably have more debt than they would like. It will be limited to the capacity to spend money.”

As for oilfield-service availability, “the ability to take on more frack jobs might be a limiting factor in how much growth you see,” he added. “And the logistics of dealing with this much sand—it’s hard to believe. Look at a 50-million-pound frack job.”

A tractor-trailer carries 50,000 pounds of sand. For a 50-million-pound frack job, “it’s 1,000 trucks. The logistics for 1,000 trucks to deliver sand is just shocking when you think about it.”

M&A and Wall Street

According to Baker Hughes, there were 160 gas rigs at work in the Haynesville in early 2011. That declined to 11 in early 2016. The late February count was 35. Among the rigs, 22 were drilling in DeSoto, Caddo, Bossier and Red River parishes.

Operators in the play are primarily Chesapeake, BHP Billiton Ltd., Goodrich, Comstock, Exco Resources Inc., Aethon Energy Management LLC, GeoSouthern Energy Corp, Indigo, Matador Resources Co., QEP Resources Inc., Vine Oil & Gas LP and Covey Park Energy LLC. In addition, in East Texas, Canaan Resource Partners LP has entered a farmout on Black Stone Minerals LP leasehold for Bossier and Haynesville.

Dallas-based Vine bought 107,000 net acres in the Haynesville core in 2014 from Shell Oil Co. for $1.2 billion. Covey Park bought 41,500 net acres from Chesapeake recently for $465 million, including interest in 326 gross operated and nonop wells producing 50 MMcf/d net. Indigo bought 78,000 net from Chesapeake for $450 million. It involves 250 wells producing 30 MMcf/d net.

After both deals, Chesapeake now holds some 250,000 net acres. Of 17 rigs it had at work portfolio-wide in late February, three were drilling the Haynesville.

Covey Park already held 321,000 gross, 218,000 net, in Texas and Louisiana for Haynesville and Bossier before adding the Chesapeake package, and it was producing 325 MMcf/d net. Proved reserves were 2.5 Tcf. Additional acquisitions have been from Encana Corp., EP Energy Corp. and Penn Virginia Corp.

Indigo’s additional acquisitions have been from EP Energy Corp. and Compass Production Partners LP.

TPH & Co. analysts expect Matador, which has a growing position in the Delaware Basin, may sell its Eagle Ford and Haynesville positions in the future. Meanwhile, QEP is refracking vintage Haynesville wells this year at an estimated cost of about $4 million each. It’s expecting to double its Haynesville production.

Subash Chandra, managing director and senior equity analyst for Guggenheim Securities LLC, reported in January that IRRs from the Haynesville have grown to some 80% at $3 gas.

Meanwhile, the Marcellus is delivering EURs averaging 2.4 Bcf per 1,000 feet, but the Haynesville’s transportation costs are lower, he added.

With the Haynesville’s average annual decline rate at 33% on the current 6 Bcf/d it is making, “we estimate it would take some 180 wells per year (across the play) to hold production flat,” Chandra wrote. “The current rig count should deliver over 300 wells.”

Regarding Comstock, KeyBanc’s Stevens reported in November that “the Haynesville renaissance is legitimate with rates of return that could rival Appalachian dry gas given stronger IP rates and lower transportation costs.”

If its convertible notes are converted to equity, “Comstock reduces leverage from 7.3x EBITDA at the end of 2017 to 3.7x at the end of 2018 (at) $2.88 an Mcf.” He added, “This is an important step toward bringing the company back to financial health with an ability to focus on its core operations in the Haynesville.”

The 20% increase in EURs by using 3,800 pounds per lateral foot, rather than 2,800, costs between $200,000 and $500,000, he wrote. As D&C times improve and other service costs have declined, overall well cost remains at $8.5 million for a 7,500-foot lateral, generating a 100% IRR at $3 gas.

Comstock’s Allison noted to Investor the Haynesville’s proximity to demand: “Just look at where our gas is. The demand on the Texas and Louisiana coasts is very strong and growing—LNG, electricity, petrochem, Mexico. Our gas supply can reach those markets at low cost. Northeast production is 1,000 miles away.”

Haynesville gas is connected to seven intra- and interstate pipelines with four being 42 inches in diameter. “We’re the competitive economic basin.”
Goodrich’s Turnham was expecting uplift in Haynesville producers’ stock prices from some private producers going public. Guggenheim’s Chandra cited media reports that Vine, Covey Park and Indigo may IPO. A rumor is that GeoSouthern may as well.

Turnham said, “The minute that happens and the buyside starts to focus on the Haynesville and these results again, it’s going to be in vogue again—unless gas prices collapse; we don’t think they will.”

Goodrich has 12 MMcf/d hedged this year with a costless collar of $3 to $3.60. “We think people will ultimately realize this year that our balance sheet is in great shape. We’re talking about exiting 2017 with less than 1.0x net debt to EBITDA.

“It’s our job to tell the story. The Haynesville will convince people on its own.”