Helmerich & Payne Rig 519 sits atop a rise along the Texas Gulf Coast in DeWitt County southeast of San Antonio, surrounded by low hills covered in oak and mesquite stretching to the horizon. Cows, ubiquitous in this part of the world, cluster under the shade of a tree a few dozen yards away, quietly oblivious to the fact that they are above a multibillion-dollar, world-class resource.

Beneath lies the Karnes Trough, a resource-rich feature of the Eagle Ford Shale and generally considered the heart of the play. Rig 519, working for a partnership between operator BHP Billiton Petroleum and Devon Energy Corp., grinds away on the Hansen B Oliver D-3H, 18,000 feet downhole out of a total measured depth of 19,300 feet. It is the fourth well of six planned for this pad. BHP estimates ultimate recovery of 1.1 million barrels of oil equivalent (boe) per well here.

Just six months prior, Devon paid $6 billion for the privilege to participate here, buying assets from GeoSouthern Resources.

“The economics in the basin are among the best in the U.S.--the world,” said Doug Reynolds, managing director and head of U.S. business for Scotia Waterous, a Houston-based M&A firm. “It’s no surprise that, with good economics around undrilled locations, buyers want exposure to that.

“Devon, which has experience across just about every basin in the U.S., decided to put down $6 billion for an Eagle Ford entry. That speaks volumes about the attractiveness of the basin.”

Since Devon announced the company-redefining acquisition in November, three additional major deals followed, totaling more than $12 billion in aggregate. Those deals introduced three new entrants into the Eagle Ford--Encana Corp., Baytex Energy and Devon--and spotlighted a growing consolidator, Sanchez Energy. Over the past year and a half, a host of additional lesser dealmaking has percolated.

Title to the Eagle Ford is in play.

Drivers and motivators

“It’s been active lately--the most liquid play in terms of deal flow,” observed Jefferies LLC managing director Bill Marko. “It’s a large play, and it’s still relatively early days in understanding the entire play. But at the same time, you’ve had companies take it as far as they want to take it, and want to cash out.”

While the play is 200-plus miles east to west, deal activity coalesces along the wet gas-condensate band along the trendline. “That’s the area with the best returns-- good pressure and type curves, and a high concentration of liquids production,” Marko said, whose firm advised Sanchez on its latest Eagle Ford acquisition from Royal Dutch Shell, as well as GeoSouthern.

“It’s a hotbed of drilling activity and good wells results--the volume growth is nothing short of startling,” Scotia Waterous’ Reynolds concurred. “We’ve never seen a basin grow to over a million and a half boe’s a day in a four-year period.” And with more than 9,000 wellbores in the basin, “it’s pretty well de-risked. That’s attracting a lot of people into the basin.”

Particularly for new entrants like Devon, Encana and Baytex. “They’ve got to find their way in to one of the best basins in the U.S.,” he said.

Not surprisingly, two of those three, Devon and Encana, were once leading natural gas producers in the U.S., now looking to boost oil and liquids portfolios. The other, Calgary-based heavy oil producer Baytex, was also looking for diversity into the Eagle Ford’s light crude.

Although largely de-risked, the Eagle Ford’s core continues to morph as new technology is brought to bear at the fringes. “We’re seeing longer laterals, more aggressive completion techniques, and a better understanding of the subsurface,” said Reynolds. “What was thought of as not necessarily core is now becoming core because of the economics it generates.”

While acreage in Karnes and DeWitt counties remains prime, the northeast extension into Gonzales and Lavaca counties, and southwest in Dimmitt and LaSalle counties, is gaining popularity with buyers. “These areas are producing EURs [estimated ultimate recoveries] and well returns that are consistent with a core-type definition.”

But fundamentally what attracts companies to the Eagle Ford are the returns. “Seventy to 100% drill-and-complete returns are pretty fantastic. In what other business do you get returns like that?” Reynolds questioned. Adding to the prize: “The economics of undrilled locations have improved dramatically in the last two years.”


Above: While recent A&D activity has trended up and down the 200-plus-mile-long Eagle Ford Shale, most all acquisitions fall within the liquids-rich band.

Liquids transfusion

The Devon/GeoSouthern deal was a trumpet call, the largest deal to date in the Eagle Ford, surpassing by almost double Marathon’s purchase price of Hilcorp Energy Co. assets for $3.5 billion in 2011, or $21,000 per acre (subtracting production). Yet Devon’s acquisition of 82,000 net Eagle Ford acres involved a largely nonoperated position and assets further along the development timeline with about five years of drilling locations remaining. Why pay so mightily for assets with limited sight?

Simply, liquids. Devon’s transition to a U.S.onshore unconventional oil producer, slow to mature organically, needed a jolt of java.

“Devon needed an anchor asset,” said Global Hunter Securities analyst Sameer Uplenchwar. “Devon needed one asset where they could deploy capital and identify it as the primary asset.”

Private-equity-backed GeoSouthern provided the answer. It had taken the largely nonoperated asset as far as it wanted, and would need heaps more cash to keep up with mega-partner BHP Billiton’s drilling plans. But only a handful of buyers could afford the ticket for GeoSouthern’s exit. Devon fit the bill.

Devon plans to invest about $1.1 billion in the Eagle Ford this year and will participate in drilling more than 200 wells. In addition to its 50,000 net acres being drilled by BHP, it holds 32,000 net operated acres in Lavaca County. For its 10 months of ownership in the play this year, the company’s net production is expected to average between 70,000 and 80,000 boe/d, significantly moving it toward the 60/40 oil-gas ratio it seeks.

“To do that, they needed something like an Eagle Ford. Doing that organically takes time,” said Uplenchwar. Devon has stated it wants to reach 125,000 bbl/d production, but he believes the goal is closer to 150,000. The company is targeting a companywide 25% annual growth rate bolstered by this asset.

“Devon is trying to triple production over the next three years, which should help them make sense of this asset,” Uplenchwar said, referring to the valuation. “They say they’re paying for 1,200 locations, which is fair value--no upside.” But if they can find additional locations, “that’s all upside.” Otherwise, “it’s a stopgap for the next four years until something else in the portfolio ramps up to that level and will take over.”

"Jefferies’ Marko sees the deal as a starter position for Devon. “This is not going to be where they finish, I presume. They’re getting an entry into an attractive play and will go from there.This is just the first step."

(For a detailed look inside the Devon/GeoSouthern deal, see the July 2014 issue of Oil and Gas Investor.)

The operator

Devon's acquisition of GeoSouthern directly impacts BHP Billiton Petroleum, headquartered in Houston. The two are now 50/50 partners on about 100,000 gross acres in DeWitt County. BHP's development of the play is a large reason Devon coveted the acreage so highly.

“Our working relationship with Devon is excellent and, philosophically, we’re aligned on all things,” said Rod Skaufel, BHP asset president, shale. "Devon has a long history in shale, and they bring a lean manufacturing mindset. They're a strong technical organization which is complementary to what we're doing."

When BHP bought Petrohawk Energy in 2011, it became operating partner to GeoSouthern. Under the legacy agreement, BHP remains operator of the subsurface including drilling and completing wells, and Devon assumes operatorship of the producing wells and facilities. The upside of the deal: Devon has more financial capacity and operating expertise than its predecessor.

The Eagle Ford is by far BHP's largest producing field, at 180,000 boe/d, over its next best, Bass Strait offshore Australia, at 100,000 boe/d. That’s up from 50,000 in August 2011 when it took over from Petrohawk.

BHP’s activity focuses on Black Hawk Field, 57,000 net acres in Karnes and DeWitt counties, where it has 14 of its 17 Eagle Ford rigs running. Devon is partner on the DeWitt acreage. IP rates hover around 1,300 boe/d--mostly condensate--on a stabilized rate. Internal rates of return (IRR) in Black Hawk average 70%.

“Clearly, our position in Black Hawk is as good as it gets,” Skaufel said. “We didn’t realize at the time [of acquisition] that it was as good as it turned out to be. The productivity at Black Hawk is prolific.”

Hawkville, however, with 250,000 net acres in LaSalle and McMullen counties and 100% operated, is a tale of two fields. The northern tier is characterized by a mix of 60% liquids with gas. EURs are similiar to Black Hawk, 900,000 bbl, but initial liquid rates are 35% to 40% lower than Black Hawk.

“In the north, where we’ve got higher liquids yields, economically those wells compete very well,” at about 25% IRR, Skaufel said. Three rigs are active here.

But where the northern Hawkville region is rich in condensate and natural gas liquids, the southern end steps down to dry gas. “It’s gassier than what we had originally expected as we’ve delineated the field,” Skaufel said. Lease terms here involve obligation drilling, and the company has acreage that it is either farming out, or letting expire. “It doesn’t compete for capital with the rest of our portfolio. Preferentially, we’re investing elsewhere.”

That philosophy reflects dealmaking in the gas window as well, which is essentially nonexistent.

BHP is in full Eagle Ford development mode, particularly at Black Hawk, yet it continues to refine its completion practices. It has changed from low-temperature gel systems to high-temperature fiber systems. BHP spends $10 million per Eagle Ford well.

“Right now, we continue to spend additional capital on our completions, based on early results, which I categorize as encouraging. We’re homing in on the recipe. We’ll spend extra money on the completion if we believe there’s an incremental rate of return with that money. We believe there’s continued optimization of the completion.”

As a result, the company is considering refracking wells older than two years with new techniques. “We want the refracks to have incremental economics of 20% or greater.”

Likewise, spacing tests are ongoing. Early Black Hawk wells were spaced 660 feet between wellbores (80 acres). BHP is now testing down to half that.

“The majority of Black Hawk will be be- tween 440 and 330 feet,” he said.

BHP has about 950 producing wells in the Eagle Ford and is drilling an additional 300 to 350 wells per year. Some $3 billion in annual capex is directed into the play. Skaufel figures Black Hawk has about another three years of drilling on current spacing assumptions.

“At that point we’re migrating those rigs from Black Hawk to the Permian. Our objective is to build our liquids-rich position in shales, whether that’s Eagle Ford, Permian or another play in the U.S. I’d love to do it organically, but we would be willing to do it by acquisition.”

The trash to treasure effect

Drillinginfo co-founder, chairman and CEO Allen Gilmer sees another driver bringing Eagle Ford assets into play: inefficient operators condemning good rock.

“There is a difference in operational capacity,” Gilmer said. “Companies that cannot get up to speed on operating their acreage are having to find others to take it over.”

Drillinginfo’s studies show that the better op- erators produce 30% to 40% more than the median, and three or four times as much as the worst operators, given the same quality of rock. And although rock quality varies across the play, operational laggards remain consistent, he said.

“You have to drill an economic well to create value, so if you drill uneconomic wells, you have not created the very important PUD [proved undeveloped] locations” surrounding those wells. “If you’re not creating PUDs, then you’re destroying capital at an accelerated rate. There is a lot of good acreage that had bad wells drilled on it early on that got condemned as bad geology.”

Thus what might look like condemned geology is gold to competent and efficient operators.

Early on, during the land-grab phase, smaller companies that could acquire positions hung onto the conventional mantra that whoever holds the acreage wins, and relied on service company contracts to supply the unconventional intellect. Alas, this strategy proved futile.

“We’ve seen this over and over again,” said Gilmer. “It calls into question the meme that oilfield service companies are an efficient technology transfer agent. The reality is that’s not the case.”

While service companies have a qualitative view on certain factors, drilling economic unconventional wells involves a host of factors beyond the service companies’ expertise. “Being a quality operator involves dozens of things that contribute to maximizing that well.”

The “smart ones,” he said, recognized their limitations and simply didn’t drill, “because they realized if they didn’t know what they were doing, they had as good a chance of destroying value as they did in building value.”

Gilmer expects “a lot of movement” with Eagle Ford properties in the near term, “because there’s never been a bigger disparity between those that know what they’re doing and those that don’t.”

Interestingly, operator size doesn’t matter in this regard. Large and well-equipped companies also can succeed at condemning otherwise good acreage. Take Shell’s Harrison Ranch.

“Of all the wells Shell drilled,” said Gilmer, “they only drilled a handful of economic ones. They didn’t generate any PUD values at all. If you look at the original amount they spent on it, then at the amount for drilling, they took a huge haircut on that sale to Sanchez. And Sanchez is a smart company--they spend a lot of time on their analytics.”

Rising Sanchez

Sanchez Energy is emerging as an Eagle Ford consolidator. From June 2013 through May 2014, Sanchez entered four Eagle Ford deals totaling more than $1.1 billion. The two largest deals were acquired from Hess Corp. for $280 million and Royal Dutch Shell for $639 million, both large energy companies looking to tighten their shale portfolios by exiting Eagle Ford.

“The Hess deal was a great opportunity,” said Sanchez Energy president and CEO Tony Sanchez III. “We added a large number of PUDs.”

A C.K. Cooper research report at the time of acquisition stated the PUDs came at a great price. “The transaction appears quite favorable for Sanchez as production was acquired for only $59,000 boe/d, or $19.70 per boe of proved reserves, which attributes no value to the upside on the 43,000 net acres.”

Sanchez Energy entered 2013 producing about 4,000 boe/d. Now that number stands at 45,000 per day and growing, largely due to the organic opportunities afforded by these acquisitions. And the Eagle Ford is in a region Tony Sanchez III knows well, as a third-generation oilman to work South Texas.

Houston-based Sanchez purchased 43,000 net acres in Dimmit, Frio, LaSalle and Zavala counties in the Hess acquisition, with Moelis & Co. advising. Over the past year it has trimmed well costs from $8.8 million to $5.5 million. “We were far more successful at getting costs down than we originally thought possible,” Sanchez said. “For every $1 million cut out of our well costs, we can improve internal rates of return by 10% to 15%.”

But while the first three deals flew under the radar as Sanchez scaled up, the acquisition from Shell garnered headlines. Shell had purchased the 106,000-acre Harrison Ranch lease four years prior for $1 billion, and by some estimates invested $2 billion additionally into the play. Nevertheless, Shell divested its South Texas position as part of its restructuring of its North American resource plays portfolio.

Chad Mabry, an analyst with MLV & Co., said the deal is a home run for Sanchez. He puts the “very favorable” acquisition metrics at $10.65 per proved boe, and $32,000 per flowing barrel. The deal doubles Sanchez’s reserves and production.

“The stage the Eagle Ford is at right now, there just aren’t very many 100,000-acre, 100%-operated positions out there. The fact they were able to secure this at such favorable terms is a positive for the company. Most other companies didn’t have the bandwidth to make this happen.”

“We’re trying to be opportunistic,” Sanchez said. “When the opportunity comes to pick up solid geological assets underpinned by strong cash flow and reserves, we need to be in a position to pursue them.” And metrics are in the eye of the beholder, he believes. “The premium is relative to what the buyer sees in terms of op- portunity. We might pay a premium for opportunities others may not see."

Where Shell's 176 wells targeted upper Eagle Ford, Sanchez will aim its initial development program into the lower Eagle Ford, where offset operators such as Rosetta Resources and Anadarko Petroleum have had success. Per-well EURs in these offsets show 1.2 million boe (MMboe) of resource. “The lower Eagle Ford is where you want to be,” Sanchez said. “It’s nice and thick throughout.”

Sanchez plans to complete the 22 wells waiting on completion at the time of sale, which closed at the end of June, and continue the current two-rig program with $350 million annual capex directed to the ranch, now dubbed Catarina by the company. Sanchez is conservatively identifying 600 lower Eagle Ford locations at Catarina, in which it anticipates generating at least 35% to 50% IRRs.

“We feel confident we can operate the assets in an efficient manner,” Sanchez said. “We’ve been focused on utilizing technology and process improvement to lower our cost basis, and can generate a competitive rate of return because of that.”

An added bonus: “Shell proved up the upper Eagle Ford--we’re now the highest volume producer in the upper Eagle Ford.”

Pro forma Shell, Sanchez holds 226,000 net acres up and down the Eagle Ford oil/condensate trend line, as well as 57,000 early appraisal acres in the Tuscaloosa Marine Shale, with total annual capex of $1 billion. It is running eight rigs across the Eagle Ford. The majority of its capital is aimed at its 70,000-acre Marquis asset in Fayette and Lavaca counties, on the far northeastern extent once considered fringe, where Sanchez runs three rigs. With 56 wells producing, estimated recovery is 450,000 to 550,000 per well; returns are 33% to 67%.

“We’ve been pleasantly surprised by the strength of production” in southern Fayette County, he said. “The IP rates are from 800 to 1,200 barrels a day, and we control the choke. Pressures are strong, and decline curves are looking good.”

Incorporating the Shell assets, Sanchez says his $2.3-billion market cap company has the capacity to do an even larger deal, and is seeking more. “We’re looking for growth opportunities that provide at least five years to 10 years drilling inventory, and the Shell deal provides a multitude of years of running room.”

Baytex's big bet

Like Devon, Baytex Energy Co. paid upsized metrics for a nonoperated piece of the Eagle Ford. Closed in June, Baytex, based in Calgary, acquired Aurora Oil & Gas Ltd. for C$2.6 billion (US$2.45 billion). Aurora was a 25% partner to Marathon Oil Corp.’s prized SugarKane Field portfolio in Karnes and Atascosa counties, with 22,200 net acres (which includes 2,700 net acres 100% company operated).

AltaCorp Capital analyst Dirk Lever estimates Baytex paid approximately $88,000 per flowing barrel for Aurora’s 29,000 bbl/d net. Thirty-day IPs from 800 to 1,000 boe/d, and EURs in excess of 500,000 boe, results in IRRs greater than 100% and payouts under two years.

It’s a growth and sustainability asset for us,” said Baytex CEO James Bowzer. “When looking for assets, we’re looking for high rates of return that throw off enough cash to support our dividend model, with enough longevity to do that for five to seven years. We want to be in resource plays that have some risk taken out by significant delineation. ”

Unspoken but instrumental in the union is Bowzer’s history: Before becoming Baytex CEO, he was vice president of North America for Marathon--Bowzer oversaw the exact assets he’s now purchasing.

While the Eagle Ford assets provide growth for Baytex, a yield-oriented E&P, the light crude produced by the play adds diversity to its Canadian heavy oil production, Bowzer said.

“There have been transportation bottlenecks out of Canada, and the WCS [Western Canadian Select] differential at times widens out to minus C$30 or worse. So the Eagle Ford provides access to a crude that is lighter and in the Gulf Coast markets.”

In addition to the 20,000 acres in partnership with Marathon, Baytex also acquired 2,000 operated Eagle Ford acres, and another 14,000 acres in the Eaglebine. While the operated Eagle Ford position is producing, the Eaglebine is purely exploratory at this time, although other companies are drilling offset wells.

And like Devon, Baytex is a stronger financial and operational partner for Marathon than was Aurora. “If Marathon were to have stepped on the accelerator on the project, Aurora proba- bly would have had trouble coming to the table with capital,” Lever said.

Baytex has established a Houston office and plans to be active with Marathon in the development of the assets. That includes Austin Chalk development. “There is upside in the Austin Chalk that looks pretty good on our combined acreage,” Bowzer noted.

Baytex expects to spend about $450 million annually in the Eagle Ford, for approximately 50 net wells.

“For us, it was simply quality of assets,” he said. “The Eagle Ford itself is one of the best plays in North America. It was an asset that was delineated with a lot of growth potential. And the expenditures you put forth are at a very high rate of return. That’s why we pursued this. We’d like to have more.”

Encana's entry

In a mad dash to funnel capex to organic liquids growth, Encana Corp.’s $3.1-billion deal for Freeport-McMoran’s (fka Plains Exploration & Production) Eagle Ford position is its first acquisition toward that end. Its ability to pay cash--on hand from recent gas-weighted sales--netted the company a fast deal at a favorable valuation--and adds a sixth core play to its high-graded portfolio.

In June, Encana announced the deal for 45,000 net acres in Karnes, Wilson and Atascosa counties. Scotia Waterous advised. The catch: just 400 drilling locations remain.

“That asset is in total harvest mode,” said Global Hunter’s Uplenchwar. “It’s already peaked. The production of 50,000 barrels a day is going to be 50,000 barrels for the next four to five years; it’s not going to 80,000. They bought it for cash flow.”

Yet he still deems the deal a good move for Encana, whose gas assets were declining about 20% annually.

“Encana is going to spend $600 million in the Eagle Ford” on the new assets, he said, “and they’re going to get about $1.1 billion back, so they get half a billion dollars free cash flow out of the gate. If I can put $1 in and get around $2 back, I’ll do that every day.”

AltaCorp’s Lever sees a similar motivation. “If you sell down your asset base, and other assets like the Tuscaloosa Marine Shale are on the come and not yet commercial, then you’ve got to backfill” with a cash-flow base.

Scotia Waterous’ Reynolds sees more upside to the madness.

“This gives Encana a great platform in the Eagle Ford to apply what they do very well--manage the subsurface. They’re quite experienced drilling unconventional wells, and I think they’ll do well with this.

“It’s not just a purchase for cash flow by any stretch,” he said. “Whether in the form of downspacing to 20 to 30 acres, or stacked completions or refracking, there will definitely be successful attempts at getting more oil out of the ground. There’s upside simply by holding good rock in the Eagle Ford.”

What goes around

Follow this tale if you can:

In 2011, the Petrohawk Energy Corp. management team that originally opened up the Eagle Ford Shale ultimately sold the company to BHP, along with a noncompete agreement in the Eagle Ford. They subsequently reformed as Halcón Resources and bought GeoResources Inc. which, among other plays, held Eagle Ford interests. Squeezed by the noncompete, Halcón then sold the Eagle Ford package to privately held Oak Valley Resources and its private-equity partner, Parallel Resource Partners, in July 2013. As it happens, Oak Valley is the reformation of the GeoResources management that had built GeoResources’ Eagle Ford holdings in the first place.

So for Frank Lodzinski, former GeoResources CEO and currently Oak Valley CEO, what goes around comes around.

“We were fortunate to team up with Parallel to buy back the Eagle Ford property from Halcón and other joint owners,” Lodzinski said. “We think there’s considerable opportunity on the acreage block for Eagle Ford development and for the Austin Chalk, the upper Eagle Ford and potentially other formations.”

Following Lodzinski’s historic model of reverse takeovers of public companies to access public capital, Houston-based Oak Valley in May initiated a merger with Earthstone Energy out of Denver, with an expected closing in September.

Uplenchwar said, “This merger means there is now another publicly traded company in this area where the upper Eagle Ford is looking increasingly promising.”

Oak Valley holds a 30% operated interest in 50,000 acres in Gonzalez and Fayette counties (about 15,000 net) in the Eagle Ford oil window, with the remainder held by Parallel. When the acreage was first leased, it was considered by some to be on the northeastern fringe of the play. But a half-dozen wells de-risked the acreage and a 3-D seismic survey under GeoResources shows promise.

Now, Lodzinski says, “the play has progressed to the north and some of the skeptics now say we are in the heart of the play. We’ve proven the commerciality. We have a high degree of confidence in this asset.”

The assets today produce 6,700 boe/d from 42 wells. Two rigs are dedicated to the Eagle Ford, one to the Austin Chalk. The company identifies 240 locations between the two formations.

Lodzinski said, “We’d like to prove those can be doubled in the Eagle Ford and further increased with other objectives.”

Current spacing stands at 1,000 feet between wells, with developments on its southern acreage at 500 feet.

Oak Valley has published 30-day IPs on its Eagle Ford acreage of 700 to 750 boe/d, but pending SEC filings related to the merger, has not disclosed EURs. However, Lodzinski stated, “EURs will be competitive with other operators in the area.”

Oak Valley’s 2014 capex is about $100 million, with about $78 million directed toward Eagle Ford and Austin Chalk. Eagle Ford wells cost $7.5 million to $8 million, and Austin Chalk wells half that.

Earthstone holds interests in the Rockies, as did GeoResources, and Lodzinski would like to re-establish the GeoResources plan and track record in both the Eagle Ford and the Bakken.

Yet expansion in the Eagle Ford remains priority. “The sooner the better,” Lodzinski said. “This is a starter position like we had at prior entities. I want to get in the hunt and compete. We’ll go anywhere in the Eagle Ford we can make a buck.”

He acknowledged Eagle Ford metrics are pricey, but places confidence in his operational team to make full-price acquisitions accretive.

“We can operate, drill and complete with the best of them,” he said. “If you pay full price and bust every AFE [approval for expenditure] by 20%, you’re going to shoot yourself in the head. But if you pay full value and reduce D&C [drill and complete] costs while increasing production and EURs, now you’re adding value.”

He calls it the 20-20 plan: “Gut up and do it, then reduce drilling costs by 20% and increase EURs and production by 20%.”

More to come

What’s next? The general consensus is the Eagle Ford is in a period of transition, as acreage deals evolve to production weighted, and early entrants seek exit by hook or crook. And it’s a sellers’ market, said Reynolds. “Good packages don’t last long.”

Drillinginfo’s Gilmer projects less than 10% of the Eagle Ford is developed, if measured at 40-acre spacing, where he estimates operators will ultimately settle. That’s plenty of upside for dealmaking, he believes. Further, expiring Eagle Ford acreage is shaking loose. “It’s interesting the amount of acreage that is being dropped in the next 90 days,” he said, “whether because they ran out of money or couldn’t get a deal done.”

Said Marko, “Everybody that wants liquids-rich has the Eagle Ford at the top of their list.”

“We’ll see continued activity in the play,” surmised Reynolds. “There are a lot of players, and for whatever reason, companies will decide to move on. You’ll see continued solid demand just given the strong economics in the play. And if the basin continues to outperform expectations, values will follow that.”

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