From giant operators like Marathon Oil Corp. and ConocoPhillips Co. to companies with private equity backing such as Venado Oil & Gas LLC, E&Ps are ramping up again in the Eagle Ford Shale after a prolonged sleep in which the local rig count plummeted from 200 in early 2014 to below 40 last summer. Of all the plays where the recovery is underway, the percentage increase in rig count is among the highest in the Eagle Ford—about double.

At press time some 86 rigs were working in the play. Higher-intensity fracks now enable each new well to deliver more oil and gas than in the past, and drilling-speed gains are delivering new wells faster. The Eagle Ford has produced 3.8 billion barrels of oil equivalent (Bboe)—45% oil, 42% natural gas and 13% condensate—since its discovery in 2008. Current daily production is about 1.2 million barrels of oil and 6 billion cubic feet (Bcf).

With more than 14,000 wells now, the Eagle Ford is not a new play. “I’d say it is maybe in the fourth or fifth inning,” one operator told Oil and Gas Investor. “There is definitely a lot more to do, even though a large amount of capital has been spent to figure out what works. Now, it is more about making small design adjustments to incrementally improve well returns.”

Eagle Ford production peaked at 1.75 mil-lion barrels a day (MMbbl/d) and fell by nearly 40% during the downturn until trending up again to the current level. The U.S. Energy Information Administration (EIA) expects this reversal will continue into next year.

The fact that the Eagle Ford yields oil, gas and NGL is a plus, if one has acreage in each hydrocarbon window and can pick and choose one’s commodity. In Webb County, Texas, alone—on the southwestern end of the U.S. side of the trend—gas production has soared from 100 million cubic feet a day (MMcf/d) in 2010 to 2 Bcf/d now.

Houston and Corpus Christi petrochemical complexes are not far away, and gas exports are growing. So, the play is well positioned geographically.

But the spotlight has turned to the stacked pay of the Permian Basin and Oklahoma. “The Eagle Ford took a back seat to the Permian during the crash,” analyst Irene Haas of Wunderlich Securities Inc. wrote in a recent report focused on the northeastern Eagle Ford counties. “While we are big fans of the Permian and appreciate the attractiveness of the stacked pays, we believe that the Eagle Ford is still a solid and prolific trend.”

Breakevens

WoodMackenzie has estimated the Eagle Ford breakeven now averages $48 to $50/bbl, right between Oklahoma’s Scoop/Stack and the Midland Basin’s Wolfcamp breakevens. However, the Eagle Ford breakeven range is a wide $30 to almost $70, depending on where it’s drilled in the 120-mile-long fairway, Wood-Mac added.

In a February report, Bernstein Research analyst Bob Brackett found that the Eagle Ford’s breakevens are variable with large non-core areas yielding economically challenged wells. Because it was the hot play before the Permian’s and Scoop/Stack’s recent horizon-tal drilling ascendance, it is further along the maturity curve.

Operators drilled their best wells first, so he anticipates that “in the future, the industry will drill worse wells. We expect single-well breakevens to rise from about $40/bbl today toward $60/bbl in two years … and, if activity returns from today toward 190 rigs by 2020, the Eagle Ford will fail to reach its former peak.”

He calculates that more than 50% of the locations that break even under $50 have already been drilled. About 80,000 locations remain, assuming 35-acre spacing or 18 wells per square mile, he added, but only two years’ worth of inventory that would break even below $55/bbl.

The formation tends to decline faster than some other unconventional resource plays, so fallout from the drilling lag during the past 18 months has been stark in some cases. For example, Pioneer Natural Resources Co.’s Eagle Ford output fell by half from first-quarter 2016 to first-quarter 2017 from about 41,600 boe/d to 22,180 boe/d. Production fell in all three categories: oil, gas and NGL.

Pioneer’s 59,000 net acres are HBP, so it can afford to back off and focus on its large Permian leasehold. However, it is currently operating two horizontal rigs in the Eagle Ford and, in April, it began completing drilled but uncompleted (DUC) wells there again.

Its objective this year is to keep pushing the technology envelope to ensure wells are economic if oil remains at or below $50/bbl, according to company reports. That involves longer laterals—in its case, 7,500 feet—with higher-density completions of 2,000 pounds of proppant per lateral foot.

On first-quarter conference calls, several other Eagle Ford operators, including Car-rizo Oil & Gas Inc. and SM Energy Co., also reported that they are testing 2,000 pounds per foot in the Eagle Ford.

In fact, proppant use throughout the play is now trending above 19 million pounds per well, according to the Well Site Market Report, a new weekly newsletter affiliated with Hart Energy and written by Richard Mason. (See his monthly column, “E&P Momentum,” in this issue.)

The newsletter reported recently that “70% of all Eagle Ford wells now include laterals of at least 7,500 feet. Cabot Oil & Gas Corp. and Chesapeake Energy Corp. have been averaging more than 11,000 feet, with the latter reporting one well that went out 14,000 feet.”

Chesapeake CEO Doug Lawler said on its first-quarter conference call, “Our growth rate will be driven from three assets: the Eagle Ford, the Powder River Basin and Midcontinent, which are all poised to deliver stronger volumes as the year progresses.

“In the Eagle Ford, we set a daily oil production record from a new well with a peak rate of 2,800 barrels per day or roughly 3,200 barrels of oil equivalent. This is one of our longer lateral wells that was also completed with more sand per foot and tighter cluster spacing compared to our standard design.”

The operator plans more of these higher-intensity wells “and we believe the enhanced completions can generate both a production and economic uplift to our program,” he said, according to a SeekingAlpha transcript of the call.

Individual well metrics, such as IPs, EURs and costs, keep improving, according to additional operators’ reports, as they have continued to gain understanding of the reservoir and hone completion designs.

In a presentation at the UBS AG energy conference in May, EOG Resources Inc. reported that its lateral target has shrunk to about 20 feet from 150 feet, and the typical lateral length is 5,300 feet on 40-acre spacing. It expects its completed well costs will fall to $4.3 million this year from $5.7 million in 2015. This number includes wellsite facilities and flowback costs.

The largest Eagle Ford acreage holder and oil producer, EOG will average eight rigs there this year and complete 195 net wells. In the first quarter, EOG completed 65, and the 30-day IP averaged 1,390 bbl/d from a lateral length averaging 6,500 feet. In addition, it tested the overlying Austin Chalk in five wells in Karnes County and these had a 30-day IP that averaged 2,605 bbl/d.

Meanwhile, it added 500 “premium” locations to its holding, defining these as capable of yield-ing at least a 30% after-tax rate of return at $40 oil. Its net premium Eagle Ford locations now total 2,425. Bernstein analyst Brackett reported that, if EOG drilled 750 wells a year, which is about 50% more than in the boom year of 2014, in the play, it would not run out of Eagle Ford inventory until “the end of the next decade,” assuming 60-acre spacing.

ConocoPhillips CEO Ryan Lance said during investor events in May and early June that companywide breakevens have gone from about $75/bbl (Brent) to less than $50. In the Eagle Ford, the company will have five rigs this year, and it has 3,500 net locations to drill there at oil less than $40/bbl. Since 2014, completion efficiencies have reduced its completed well costs by half in the play, despite increasingly larger fracks of up to 300 clusters and 15.5 million pounds of sand per well, optimized spacing and stacking laterals.

He said there’s been a 40% increase in the company’s Eagle Ford resource as calculated at less than $40/bbl cost of supply and an estimated 3 Bboe total recoverable, including already-produced volumes.

In the Austin Chalk, initial results are “encouraging,” he added. Wunderlich analyst Haas numerous operators that are applying “Gen-3” completion techniques to the formation.

At the Scotia Howard Weil energy conference in March, Marathon Oil CEO Lee Till-man said the Eagle Ford provides free cash flow at a spending level that maintains cur-rent production. It plans six rigs in the play this year and to turn between 155 and 170 operated wells to sales, with two-thirds in the play’s high-margin oil window.

While the company likes the Eagle Ford, Tillman said its priorities have changed to the northern Delaware Basin and the Scoop/Stack. It sold assets in Angola, Norway and Alberta’s oil sands to move more rigs into the Permian and Oklahoma. About 30% of 2017 capex will be devoted to the Eagle Ford.

Devon Energy Corp. reported that it is also focusing on the Delaware Basin and Stack. In the Eagle Ford, it is focusing on Dewitt County. In the first quarter, its wells completed there averaged 2,100 boe/d for the first 30 days, according to the company’s website.

The EIA estimated there were 1,315 Eagle Ford DUCs in April, with operators reporting competition to lure frack crews that are flocking to the Permian Basin instead. At press time, about 30 frack crews were in the Eagle Ford, with operators complaining of patchy performance as “rusty” personnel return to work or new hires are brought on board.

Well Site Market Report reported, “It has been a long time coming—two years in fact—but drilling levels in the Eagle Ford are back to early 2015 numbers after the horizontal rig count doubled off fourth-quarter 2016 levels … that surge has led to greater demand for stimulation services … zipper fracks grew to 70% of completions vs. 70% in the first quarter.”

Billion-dollar buyers

Acquisition activity has been robust. Privately held Venado has spent more than $1 billion on deals to build its Eagle Ford position, backed by an equity investment from KKR & Co. LP. In March, it closed on an $800-million purchase of SM Energy’s nonoperated assets, including 37,500 net acres in the Maverick Basin that is in the southwestern portion of the fairway. In early June, it was closing on another 50,860 net acres for $300 million from Exco Resources Inc.

Newly public WildHorse Resource Development Corp. has spent more than $1 billion as well, buying a Clayton Williams Energy Inc. package for $400 million and 111,000 net acres from Anadarko Petroleum Corp. and KKR for $625 million. Pro forma for these deals, it is now the second-largest net-acreage holder in the Eagle Ford, right behind EOG and ahead of Sanchez Energy Corp. Chesapeake ranks fourth.

It brought seven gross wells online in the first quarter and plans 80 to 100 completions this year in the Eagle Ford, according to Wild-Horse Resource CEO Jay Graham. He estimates 60,000 of the net acres are prospective for the Austin Chalk.

Privately held EnerVest Ltd. has been drilling in South Texas’ Austin Chalk since 2007. Advantaged by that experience, it was one of the more active buyers through the downturn, adding significantly to its Eagle Ford holdings with $1.6 billion since September 2015. One of these was for 7,056 net acres from Black-Brush Oil & Gas LP for $800 million. The package came with 341 drilling locations and 5,170 boe/d, which EnerVest has now grown to 14,900 boe/d.

That and deals since are concentrated in Karnes County, where the acquired properties combined produced more than 17,000 boe/d at the time the deals were announced—the company has since increased its total Eagle Ford production to 25,800 boe/d, Jud Walker, president of EnerVest Operating, told Investor. With these deals, EnerVest has roughly 900 locations. John Walker, chairman and CEO, told Investor it’s taking the time to make sure it understands the play and to identify and buy small add-ons or pockets of nearby acreage as well.

The first thing it bought was a nonoperated asset from Alta Mesa Holdings LP for $125 million in 2015. Murphy Oil Corp. is the operator. A few months later, it bought Gulf-Tex Energy III LP assets. EOG is the primary partner on that acreage.

“We are nonop under several of their wells,” John Walker said. “They are a great partner to have because they spend so much time on the technology. Now, if we’re drilling a well ourselves, they’re willing to help us to land it right.”

Although EnerVest incorporates what it learns from EOG, it recently took that a step further. “Since we’re putting more capital to work, we’re spending a lot of time on the science,” said his son, Jud Walker.

“We hired a petrophysicist and some fairly technical geologists and an engineer to really look at all this. We want to come out of the gate as a close follower. We took a couple of extra months after the GulfTex acquisition to make sure we had all our ducks in a row.”

Since the BlackBrush deal, the company has completed 19 DUCs. “We’ve completed all those, and we picked up a rig in December 2017. We’ve drilled 25 wells so far ourselves. We’ll hold that rig for the rest of this year and also work the additional one we just picked up in May,” he said.

In its Giddings-Austin Chalk area, “we’ll look at adding a third rig later in the year. It depends on how we look at our own capabilities, whether we need to add enough people to look after these rigs and remain top-tier in whatever we do,” he added. “We think we know the perfect recipe, but we will keep experimenting.”

Like EOG and Sanchez Energy, EnerVest decided to unbundle some services by sourcing its own frack sand and horsepower, put-ting these costs under its control.

Future business considerations include more consolidation in South Texas, but John Walker said it is getting difficult to pick up Eagle Ford leasehold in such a mature play. “You probably have to buy companies.”

It has discussed joint ventures as opportunities arise. “A lot of Asians have come in to see us about them buying properties and having us operate them,” he said. “After all, we are the sixth-largest gas producer in Texas. So, we’ve gone pretty far down that path in our conversations, but so far nothing has materialized.”

EnerVest’s pads typically have two Austin Chalk and two lower Eagle Ford wells, enabling it to compare each formation. In the latter, drilling into the mudstone is based on what it’s learned from EOG’s work with 250-foot interwell spacing. However, in the Chalk, which is a brittle, fractured carbonate, 500- to 600-foot spacing is the norm at the moment, Jud Walker said.

Austin Chalk IPs are generally stronger than those in the Eagle Ford, and initial decline rates are shallower, John Walker said, so EnerVest is excited about learning to understand how the two plays tick. The Chalk wells are yielding EURs of 1 MMboe, but the lower Eagle Ford wells are about 800,000 boe, he said. “In general, these wells pay out in less than a year—some in three or four months—and that’s at current commodity prices,” John Walker said. “Obviously, the industry is so focused on the Permian right now, but we have higher EURs, lower costs and less water production here, so, therefore, our rates of return are actually higher here than in the Permian.

“The guys in the Delaware will talk about all the stacked pays they have, but we have the Austin Chalk.”

Jud Walker added: “The Chalk’s thicker and most operators think, going forward, there could be some zones higher up in the Chalk that could be economic. We’ve got a very thick lower Eagle Ford where we can stagger the zones. The upper is not as good, but certainly there are economic projects to be had, so we’ll probably test those when commodity prices get better.”

EnerVest’s first pad included laterals drilled in a wine-rack pattern. They flowed 12,000 bbl/d and 6 MMcf/d. Laterals of between 5,000 and 6,000 feet in the lower Eagle Ford are drilled in seven days, and the company uses 3,000 pounds of 100-mesh sand per foot.

“You’ve got to put all the pieces together; you can’t look only in one dimension,” Jud Walker said. “The intensity of these completions has ramped up. Very short stage spacing is the key in our laterals, and we have full 3-D coverage over our position.”

Given the number of acquisitions in the Eagle Ford by all types of operators and better drilling and completion techniques used by all of them, the industry can expect a further ramp-up in drilling this year if oil prices hold around $50/bbl. Anything higher than that would bring even more focus to the South Texas giant.

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